HAWAIIAN ELECTRIC CO INC - Quarter Report: 2011 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Exact Name of Registrant as	Commission	I.R.S. Employer
Specified in Its Charter	File Number	Identification No.
HAWAIIAN ELECTRIC INDUSTRIES, INC.	1-8503	99-0208097
and Principal Subsidiary
HAWAIIAN ELECTRIC COMPANY, INC.	1-4955	99-0040500

State of Hawaii

(State or other jurisdiction of incorporation or organization)

900 Richards Street, Honolulu, Hawaii 96813

(Address of principal executive offices and zip code)

Hawaiian Electric Industries, Inc. ----- (808) 543-5662

Hawaiian Electric Company, Inc. ------- (808) 543-7771

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.

Class of Common Stock		Outstanding July 21, 2011
Hawaiian Electric Industries, Inc. (Without Par Value)		95,877,918 Shares
Hawaiian Electric Company, Inc. ($6-2/3 Par Value)		13,830,823 Shares (not publicly traded)

Indicate by check mark whether Registrant Hawaiian Electric Industries, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x		Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether Registrant Hawaiian Electric Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x (Do not check if a smaller reporting company)		Smaller reporting company o

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Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 2011

INDEX

Page No.
ii	Glossary of Terms
iv	Forward-Looking Statements

	PART I.	FINANCIAL INFORMATION
	Item 1.	Financial Statements

		Hawaiian Electric Industries, Inc. and Subsidiaries
1		Consolidated Statements of Income (unaudited) - three and six months ended June 30, 2011 and 2010
2		Consolidated Balance Sheets (unaudited) - June 30, 2011 and December 31, 2010
3		Consolidated Statements of Changes in Shareholders’ Equity (unaudited) - six months ended June 30, 2011 and 2010
4		Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2011 and 2010
5		Notes to Consolidated Financial Statements (unaudited)

		Hawaiian Electric Company, Inc. and Subsidiaries
23		Consolidated Statements of Income (unaudited) - three and six months ended June 30, 2011 and 2010
24		Consolidated Balance Sheets (unaudited) - June 30, 2011 and December 31, 2010
25		Consolidated Statements of Changes in Common Stock Equity (unaudited) - six months ended June 30, 2011 and 2010
26		Consolidated Statements of Cash Flows (unaudited) - six months ended June 30, 2011 and 2010
27		Notes to Consolidated Financial Statements (unaudited)
46	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
46		HEI Consolidated
51		Electric Utilities
58		Bank
66	Item 3.	Quantitative and Qualitative Disclosures About Market Risk
67	Item 4.	Controls and Procedures

	PART II.	OTHER INFORMATION
68	Item 1.	Legal Proceedings
68	Item 1A.	Risk Factors
68	Item 5.	Other Information
69	Item 6.	Exhibits
70	Signatures

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Hawaiian Electric Industries, Inc. and Subsidiaries

Hawaiian Electric Company, Inc. and Subsidiaries

Form 10-Q—Quarter ended June 30, 2011

GLOSSARY OF TERMS

Terms		Definitions

AFUDC		Allowance for funds used during construction
AOCI		Accumulated other comprehensive income
ARO		Asset retirement obligation
ASB		American Savings Bank, F.S.B., a wholly-owned subsidiary of American Savings Holdings, Inc. American Savings Investment Services Corp. and its subsidiary, Bishop Insurance Agency of Hawaii, Inc. (dissolved in 2010) are former subsidiaries.
ASHI		American Savings Holdings, Inc., a wholly owned subsidiary of Hawaiian Electric Industries, Inc. and the parent company of American Savings Bank, F.S.B.
CIP CT-1		Campbell Industrial Park 110 MW combustion turbine No. 1
Company		Hawaiian Electric Industries, Inc. and its direct and indirect subsidiaries, including, without limitation, Hawaiian Electric Company, Inc. and its subsidiaries (listed under HECO); American Savings Holdings, Inc. and its subsidiary, American Savings Bank, F.S.B. and its former subsidiaries (listed under ASB); Pacific Energy Conservation Services, Inc. (dissolved on April 1, 2011); HEI Properties, Inc.; Hawaiian Electric Industries Capital Trust II and Hawaiian Electric Industries Capital Trust III (inactive financing entities); and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.).
Consumer Advocate		Division of Consumer Advocacy, Department of Commerce and Consumer Affairs of the State of Hawaii
DBEDT		State of Hawaii Department of Business, Economic Development and Tourism
D&O		Decision and order
DG		Distributed generation
Dodd-Frank Act		Dodd-Frank Wall Street Reform and Consumer Protection Act
DRIP		HEI Dividend Reinvestment and Stock Purchase Plan
DSM		Demand-side management
ECAC		Energy cost adjustment clauses
EIP		2010 Equity and Incentive Plan
Energy Agreement		Agreement dated October 20, 2008 and signed by the Governor of the State of Hawaii, the State of Hawaii Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the Department of Commerce and Consumer Affairs, and HECO, for itself and on behalf of its electric utility subsidiaries committing to actions to develop renewable energy and reduce dependence on fossil fuels in support of the HCEI
EPA		Environmental Protection Agency — federal
EPS		Earnings per share
Exchange Act		Securities Exchange Act of 1934
FDIC		Federal Deposit Insurance Corporation
federal		U.S. Government
FHLB		Federal Home Loan Bank
FHLMC		Federal Home Loan Mortgage Corporation
FNMA		Federal National Mortgage Association
FSS		Forward Starting Swaps

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GLOSSARY OF TERMS, continued

Terms		Definitions
GAAP		U.S. generally accepted accounting principles
GHG		Greenhouse gas
GNMA		Government National Mortgage Association
HCEI		Hawaii Clean Energy Initiative
HECO		Hawaiian Electric Company, Inc., an electric utility subsidiary of Hawaiian Electric Industries, Inc. and parent company of Hawaii Electric Light Company, Inc., Maui Electric Company, Limited, HECO Capital Trust III (unconsolidated subsidiary), Renewable Hawaii, Inc. and Uluwehiokama Biofuels Corp.
HEI		Hawaiian Electric Industries, Inc., direct parent company of Hawaiian Electric Company, Inc., American Savings Holdings, Inc., Pacific Energy Conservation Services, Inc. (dissolved on April 1, 2011), HEI Properties, Inc., Hawaiian Electric Industries Capital Trust II, Hawaiian Electric Industries Capital Trust III and The Old Oahu Tug Service, Inc. (formerly Hawaiian Tug & Barge Corp.)
HEIRSP		Hawaiian Electric Industries Retirement Savings Plan
HELCO		Hawaii Electric Light Company, Inc., an electric utility subsidiary of Hawaiian Electric Company, Inc.
HPOWER		City and County of Honolulu with respect to a power purchase agreement for a refuse-fired plant
IPP		Independent power producer
Kalaeloa		Kalaeloa Partners, L.P.
KWH		Kilowatthour
MECO		Maui Electric Company, Limited, an electric utility subsidiary of Hawaiian Electric Company, Inc.
MW		Megawatt/s (as applicable)
NII		Net interest income
NPV		Net portfolio value
NQSO		Nonqualified stock option
O&M		Other operation and maintenance
OPEB		Postretirement benefits other than pensions
OTS		Office of Thrift Supervision, Department of Treasury
PPA		Power purchase agreement
PUC		Public Utilities Commission of the State of Hawaii
RAM		Revenue adjustment mechanism
RBA		Revenue balancing account
RFP		Request for proposal
REIP		Renewable Energy Infrastructure Program
RHI		Renewable Hawaii, Inc., a wholly owned subsidiary of Hawaiian Electric Company, Inc.
ROACE		Return on average common equity
RORB		Return on average rate base
RPS		Renewable portfolio standard
SAR		Stock appreciation right
SEC		Securities and Exchange Commission
See		Means the referenced material is incorporated by reference
SOIP		1987 Stock Option and Incentive Plan, as amended
TDR		Troubled debt restructuring
UBC		Uluwehiokama Biofuels Corp., a non-regulated subsidiary of Hawaiian Electric Company, Inc.
VIE		Variable interest entity

iii

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by Hawaiian Electric Industries, Inc. (HEI) and Hawaiian Electric Company, Inc. (HECO) and their subsidiaries contain “forward-looking statements,” which include statements that are predictive in nature, depend upon or refer to future events or conditions, and usually include words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “predicts,” “estimates” or similar expressions. In addition, any statements concerning future financial performance, ongoing business strategies or prospects or possible future actions are also forward-looking statements. Forward-looking statements are based on current expectations and projections about future events and are subject to risks, uncertainties and the accuracy of assumptions concerning HEI and its subsidiaries (collectively, the Company), the performance of the industries in which they do business and economic and market factors, among other things. These forward-looking statements are not guarantees of future performance.

Risks, uncertainties and other important factors that could cause actual results to differ materially from those described in forward-looking statements and from historical results include, but are not limited to, the following:

· international, national and local economic conditions, including the state of the Hawaii tourism, defense and construction industries, the strength or weakness of the Hawaii and continental U.S. real estate markets (including the fair value and/or the actual performance of collateral underlying loans held by American Savings Bank, F.S.B. (ASB), which could result in higher loan loss provisions and write-offs), decisions concerning the extent of the presence of the federal government and military in Hawaii, and the implications and potential impacts of capital and credit market conditions and federal and state responses to those conditions;

· weather and natural disasters (e.g., hurricanes, earthquakes, tsunamis, lightning strikes and the potential effects of global warming, such as more severe storms and rising sea levels), including their impact on Company operations and the economy (e.g., the effect of the March 2011 natural disasters in Japan on its economy and tourism in Hawaii);

· global developments, including unrest and conflict in North Africa and the Middle East, terrorist acts, the war on terrorism, continuing U.S. presence in Afghanistan and potential conflict or crisis with North Korea;

· the timing and extent of changes in interest rates and the shape of the yield curve;

· the ability of the Company to access credit markets to obtain commercial paper and other short-term and long-term debt financing (including lines of credit) and to access capital markets to issue HEI common stock under volatile and challenging market conditions, and the cost of such financings, if available;

· the risks inherent in changes in the value of pension and other retirement plan assets and securities available for sale;

· changes in laws, regulations, market conditions and other factors that result in changes in assumptions used to calculate retirement benefits costs and funding requirements;

· the impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (Dodd-Frank Act) and of the rules and regulations that the Dodd-Frank Act requires to be promulgated;

· increasing competition in the banking industry (e.g., increased price competition for deposits, or an outflow of deposits to alternative investments, which may have an adverse impact on ASB’s cost of funds);

· the implementation of the Energy Agreement with the State of Hawaii and Consumer Advocate (Energy Agreement) setting forth the goals and objectives of a Hawaii Clean Energy Initiative (HCEI), revenue decoupling and the fulfillment by the electric utilities of their commitments under the Energy Agreement (given the Public Utilities Commission of the State of Hawaii (PUC) approvals needed; the PUC’s potential delay in considering HCEI-related costs; reliance by the Company on outside parties like the state, independent power producers (IPPs) and developers; potential changes in political support for the HCEI; and uncertainties surrounding wind power, the proposed undersea cable (to bring power to Oahu from Lanai and/or Molokai), biofuels, environmental assessments and the impacts of implementation of the HCEI on future costs of electricity);

· capacity and supply constraints or difficulties, especially if generating units (utility-owned or IPP-owned) fail or measures such as demand-side management (DSM), distributed generation (DG), combined heat and power or other firm capacity supply-side resources fall short of achieving their forecasted benefits or are otherwise insufficient to reduce or meet peak demand;

· the risk to generation reliability when generation peak reserve margins on Oahu are strained;

· fuel oil price changes, performance by suppliers of their fuel oil delivery obligations and the continued availability to the electric utilities of their energy cost adjustment clauses (ECACs);

· the impact of fuel price volatility on customer satisfaction and political and regulatory support for the utilities;

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· the risks associated with increasing reliance on renewable energy, as contemplated under the Energy Agreement, including the availability and cost of non-fossil fuel supplies for renewable energy generation and the operational impacts of adding intermittent sources of renewable energy to the electric grid;

· the ability of IPPs to deliver the firm capacity anticipated in their power purchase agreements (PPAs);

· the ability of the electric utilities to negotiate, periodically, favorable fuel supply and collective bargaining agreements;

· new technological developments that could affect the operations and prospects of HEI and its subsidiaries (including HECO and its subsidiaries and ASB) or their competitors;

· federal, state, county and international governmental and regulatory actions, such as changes in laws, rules and regulations applicable to HEI, HECO, ASB and their subsidiaries (including changes in taxation, increases in capital requirements, regulatory changes resulting from the HCEI, environmental laws and regulations, the regulation of greenhouse gas (GHG) emissions, governmental fees and assessments (such as Federal Deposit Insurance Corporation assessments), and potential carbon “cap and trade” legislation that may fundamentally alter costs to produce electricity and accelerate the move to renewable generation);

· decisions by the PUC in rate cases and other proceedings (including the risks of delays in the timing of decisions, adverse changes in final decisions from interim decisions and the disallowance of project costs);

· decisions by the PUC and by other agencies and courts on land use, environmental and other permitting issues (such as required corrective actions and restrictions and penalties that may arise, such as with respect to environmental conditions or renewable portfolio standards (RPS));

· potential enforcement actions by the Office of Thrift Supervision (OTS) (or its regulatory successors, the Office of the Comptroller of the Currency and the Federal Reserve Board) and other governmental authorities (such as consent orders, required corrective actions, restrictions and penalties that may arise, for example, with respect to compliance deficiencies under existing or new banking and consumer protection laws and regulations or with respect to capital adequacy);

· ability to recover increasing costs and earn a reasonable return on capital investments not covered by revenue adjustment mechanisms;

· the risks associated with the geographic concentration of HEI’s businesses and ASB’s loans, ASB’s concentration in a single product type (i.e., first mortgages) and ASB’s significant credit relationships (i.e., concentrations of large loans and/or credit lines with certain customers);

· changes in accounting principles applicable to HEI, HECO, ASB and their subsidiaries, including the adoption of International Financial Reporting Standards or new U.S. accounting standards, the potential discontinuance of regulatory accounting and the effects of potentially required consolidation of variable interest entities (VIEs) or required capital lease accounting for PPAs with IPPs;

· changes by securities rating agencies in their ratings of the securities of HEI and HECO and the results of financing efforts;

· faster than expected loan prepayments that can cause an acceleration of the amortization of premiums on loans and investments and the impairment of mortgage-servicing assets of ASB;

· changes in ASB’s loan portfolio credit profile and asset quality which may increase or decrease the required level of allowance for loan losses and charge-offs;

· changes in ASB’s deposit cost or mix which may have an adverse impact on ASB’s cost of funds;

· the final outcome of tax positions taken by HEI, HECO, ASB and their subsidiaries;

· the risks of suffering losses and incurring liabilities that are uninsured or underinsured; and

· other risks or uncertainties described elsewhere in this report and in other reports (e.g., “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K) previously and subsequently filed by HEI and/or HECO with the Securities and Exchange Commission (SEC).

Forward-looking statements speak only as of the date of the report, presentation or filing in which they are made. Except to the extent required by the federal securities laws, HEI, HECO, ASB and their subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

	Three months						Six months
	ended June 30						ended June 30
(in thousands, except per share amounts)	2011			2010			2011			2010
Revenues
Electric utility	$	728,738		$	584,095		$	1,374,073		$	1,132,206
Bank	66,318			71,632			131,631			142,546
Other	(737		)	(63		)	(752		)	(48		)
	794,319			655,664			1,504,952			1,274,704
Expenses
Electric utility	686,220			542,660			1,286,347			1,048,162
Bank	42,498			45,857			86,057			95,000
Other	1,940			3,516			5,512			7,204
	730,658			592,033			1,377,916			1,150,366
Operating income (loss)
Electric utility	42,518			41,435			87,726			84,044
Bank	23,820			25,775			45,574			47,546
Other	(2,677		)	(3,579		)	(6,264		)	(7,252		)
	63,661			63,631			127,036			124,338
Interest expense—other than on deposit liabilities and other bank borrowings	(24,177		)	(20,520		)	(44,317		)	(40,901		)
Allowance for borrowed funds used during construction	553			790			1,073			1,569
Allowance for equity funds used during construction	1,317			1,847			2,561			3,620
Income before income taxes	41,354			45,748			86,353			88,626
Income taxes	13,742			16,013			29,806			31,292
Net income	27,612			29,735			56,547			57,334
Preferred stock dividends of subsidiaries	473			473			946			946
Net income for common stock	$	27,139		$	29,262		$	55,601		$	56,388
Basic earnings per common share	$	0.28		$	0.31		$	0.58		$	0.61
Diluted earnings per common share	$	0.28		$	0.31		$	0.58		$	0.61
Dividends per common share	$	0.31		$	0.31		$	0.62		$	0.62
Weighted-average number of common shares outstanding	95,393			93,159			95,107			92,867
Dilutive effect of share-based compensation	162			255			287			292
Adjusted weighted-average shares	95,555			93,414			95,394			93,159

The accompanying notes are an integral part of these consolidated financial statements.

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands)	June 30, 2011			December 31, 2010
Assets
Cash and cash equivalents	$	266,746		$	330,651
Accounts receivable and unbilled revenues, net	319,533			266,996
Available-for-sale investment and mortgage-related securities	711,347			678,152
Investment in stock of Federal Home Loan Bank of Seattle	97,764			97,764
Loans receivable held for investment, net	3,580,418			3,489,880
Loans held for sale, at lower of cost or fair value	4,784			7,849
Property, plant and equipment, net of accumulated depreciation of $2,055,204 in 2011 and $2,037,598 in 2010	3,204,996			3,165,918
Regulatory assets	478,766			478,330
Other	494,527			487,614
Goodwill	82,190			82,190
Total assets	$	9,241,071		$	9,085,344
Liabilities and shareholders’ equity
Liabilities
Accounts payable	$	168,187		$	202,446
Interest and dividends payable	29,593			27,814
Deposit liabilities	4,054,949			3,975,372
Short-term borrowings—other than bank	—			24,923
Other bank borrowings	239,122			237,319
Long-term debt, net—other than bank	1,440,006			1,364,942
Deferred income taxes	316,843			278,958
Regulatory liabilities	309,809			296,797
Contributions in aid of construction	339,489			335,364
Other	796,573			823,479
Total liabilities	7,694,571			7,567,414

Preferred stock of subsidiaries - not subject to mandatory redemption	34,293			34,293

Shareholders’ equity
Preferred stock, no par value, authorized 10,000,000 shares; issued: none	—			—
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding: 95,853,329 shares in 2011 and 94,690,932 shares in 2010	1,343,537			1,314,199
Retained earnings	178,513			181,910
Accumulated other comprehensive loss, net of tax benefits	(9,843		)	(12,472		)
Total shareholders’ equity	1,512,207			1,483,637
Total liabilities and shareholders’ equity	$	9,241,071		$	9,085,344

The accompanying notes are an integral part of these consolidated financial statements.

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Changes in Shareholders’ Equity (unaudited)

	Common stock			Retained			Accumulated other comprehensive
(in thousands, except per share amounts)	Shares	Amount		earnings			loss			Total
Balance, December 31, 2010	94,691	$	1,314,199	$	181,910		$	(12,472	)	$	1,483,637
Comprehensive income (loss):
Net income for common stock	—	—		55,601			—			55,601
Net unrealized gains on securities:
Net unrealized gains on securities arising during the period, net of taxes of $2,341	—	—		—			3,435			3,435
Less: reclassification adjustment for net realized gains included in net income, net of taxes of $2	—	—		—			(3		)	(3		)
Derivatives qualified as cash flow hedges:
Net unrealized holding losses arising during the period, net of tax benefits of $9	—	—		—			(3		)	(3		)
Less: reclassification adjustment to net income, net of tax benefits of $41	—	—		—			64			64
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $2,108	—	—		—			3,488			3,488
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,801	—	—		—			(4,352		)	(4,352		)
Other comprehensive income							2,629
Comprehensive income										58,230
Issuance of common stock, net	1,162	29,338		—			—			29,338
Common stock dividends ($0.62 per share)	—	—		(58,998		)	—			(58,998		)
Balance, June 30, 2011	95,853	$	1,343,537	$	178,513		$	(9,843	)	$	1,512,207
Balance, December 31, 2009	92,521	$	1,265,157	$	184,213		$	(7,722	)	$	1,441,648
Comprehensive income (loss):
Net income for common stock	—	—		56,388			—			56,388
Net unrealized gains on securities:
Net unrealized gains on securities arising during the period, net of taxes of $1,747	—	—		—			2,646			2,646
Derivatives qualified as cash flow hedges:
Net unrealized holding losses arising during the period, net of tax benefits of $662	—	—		—			(1,039		)	(1,039		)
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $1,248	—	—		—			1,959			1,959
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $1,080	—	—		—			(1,697		)	(1,697		)
Other comprehensive income							1,869
Comprehensive income										58,257
Issuance of common stock, net	1,099	24,314		—			—			24,314
Common stock dividends ($0.62 per share)	—	—		(57,586		)	—			(57,586		)
Balance, June 30, 2010	93,620	$	1,289,471	$	183,015		$	(5,853	)	$	1,466,633

The accompanying notes are an integral part of these consolidated financial statements.

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Hawaiian Electric Industries, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Six months ended June 30	2011			2010
(in thousands)

Cash flows from operating activities
Net income	$	56,547		$	57,334
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	75,243			79,606
Other amortization	11,965			2,149
Provision for loan losses	7,105			6,349
Loans receivable originated and purchased, held for sale	(64,028		)	(136,197		)
Proceeds from sale of loans receivable, held for sale	71,829			167,583
Changes in deferred income taxes	39,051			(2,381		)
Changes in excess tax benefits from share-based payment arrangements	(55		)	97
Allowance for equity funds used during construction	(2,561		)	(3,620		)
Decrease in cash overdraft	(2,305		)	(302		)
Changes in assets and liabilities
Increase in accounts receivable and unbilled revenues, net	(52,537		)	(25,012		)
Increase in fuel oil stock	(6,509		)	(49,759		)
Decrease (increase) in accounts, interest and dividends payable	(41,989		)	1,359
Changes in prepaid and accrued income taxes and utility revenue taxes	8,333			(30,699		)
Changes in other assets and liabilities	(44,908		)	11,732
Net cash provided by operating activities	55,181			78,239
Cash flows from investing activities
Available-for-sale investment and mortgage-related securities purchased	(193,119		)	(379,896		)
Principal repayments on available-for-sale investment and mortgage-related securities	161,526			203,783
Proceeds from sale of available-for-sale investment securities	2,066			—
Net decrease (increase) in loans held for investment	(104,824		)	61,017
Proceeds from sale of real estate acquired in settlement of loans	3,977			2,118
Capital expenditures	(89,088		)	(76,659		)
Contributions in aid of construction	8,153			9,430
Other	(2,911		)	(10		)
Net cash used in investing activities	(214,220		)	(180,217		)
Cash flows from financing activities
Net increase (decrease) in deposit liabilities	79,577			(57,226		)
Net increase (decrease) in short-term borrowings with original maturities of three months or less	(24,923		)	13,023
Net increase (decrease) in retail repurchase agreements	1,803			(41,112		)
Proceeds from issuance of long-term debt	125,000			—
Repayment of long-term debt	(50,000		)	—
Changes in excess tax benefits from share-based payment arrangements	55			(97		)
Net proceeds from issuance of common stock	12,071			10,789
Common stock dividends	(47,331		)	(46,246		)
Preferred stock dividends of subsidiaries	(946		)	(946		)
Other	(172		)	(1,805		)
Net cash provided by (used in) financing activities	95,134			(123,620		)
Net decrease in cash and cash equivalents	(63,905		)	(225,598		)
Cash and cash equivalents, beginning of period	330,651			503,922
Cash and cash equivalents, end of period	$	266,746		$	278,324

The accompanying notes are an integral part of these consolidated financial statements.

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Hawaiian Electric Industries, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (GAAP) for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto included in HEI’s Form 10-K for the year ended December 31, 2010 and the unaudited consolidated financial statements and the notes thereto in HEI’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2011.

In the opinion of HEI’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the Company’s financial position as of June 30, 2011 and December 31, 2010, the results of its operations for the three and six months ended June 30, 2011 and 2010 and cash flows for the six months ended June 30, 2011 and 2010. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

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2 · Segment financial information

(in thousands)	Electric Utility		Bank		Other			Total
Three months ended June 30, 2011
Revenues from external customers	$	728,702	$	66,318	$	(701	)	$	794,319
Intersegment revenues (eliminations)	36		—		(36		)	—
Revenues	728,738		66,318		(737		)	794,319
Income (loss) before income taxes	28,603		23,806		(11,055		)	41,354
Income taxes (benefit)	11,080		8,611		(5,949		)	13,742
Net income (loss)	17,523		15,195		(5,106		)	27,612
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	17,024		15,195		(5,080		)	27,139
Six months ended June 30, 2011
Revenues from external customers	$	1,374,001	$	131,631	$	(680	)	$	1,504,952
Intersegment revenues (eliminations)	72		—		(72		)	—
Revenues	1,374,073		131,631		(752		)	1,504,952
Income (loss) before income taxes	59,870		45,533		(19,050		)	86,353
Income taxes (benefit)	22,659		16,487		(9,340		)	29,806
Net income (loss)	37,211		29,046		(9,710		)	56,547
Preferred stock dividends of subsidiaries	998		—		(52		)	946
Net income (loss) for common stock	36,213		29,046		(9,658		)	55,601
Tangible assets (at June 30, 2011)	4,279,122		4,801,483		71,422			9,152,027
Three months ended June 30, 2010
Revenues from external customers	$	584,048	$	71,632	$	(16	)	$	655,664
Intersegment revenues (eliminations)	47		—		(47		)	—
Revenues	584,095		71,632		(63		)	655,664
Income (loss) before income taxes	28,354		25,747		(8,353		)	45,748
Income taxes (benefit)	10,213		9,616		(3,816		)	16,013
Net income (loss)	18,141		16,131		(4,537		)	29,735
Preferred stock dividends of subsidiaries	499		—		(26		)	473
Net income (loss) for common stock	17,642		16,131		(4,511		)	29,262
Six months ended June 30, 2010
Revenues from external customers	$	1,132,123	$	142,546	$	35		$	1,274,704
Intersegment revenues (eliminations)	83		—		(83		)	—
Revenues	1,132,206		142,546		(48		)	1,274,704
Income (loss) before income taxes	57,866		47,483		(16,723		)	88,626
Income taxes (benefit)	21,174		17,616		(7,498		)	31,292
Net income (loss)	36,692		29,867		(9,225		)	57,334
Preferred stock dividends of subsidiaries	998		—		(52		)	946
Net income (loss) for common stock	35,694		29,867		(9,173		)	56,388
Tangible assets (at December 31, 2010)	4,285,680		4,707,870		2,905			8,996,455

Intercompany electricity sales of the electric utilities to the bank and “other” segments are not eliminated because those segments would need to purchase electricity from another source if it were not provided by consolidated HECO, the profit on such sales is nominal and the elimination of electric sales revenues and expenses could distort segment operating income and net income for common stock.

Bank fees that ASB charges the electric utility and “other” segments are not eliminated because those segments would pay fees to another financial institution if they were to bank with another institution, the profit on such fees is nominal and the elimination of bank fee income and expenses could distort segment operating income and net income for common stock.

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3 · Electric utility subsidiary

For consolidated HECO financial information, including its commitments and contingencies, see pages 23 through 36 (HECO and Subsidiaries Consolidated Statements of Income (unaudited) through Note 11).

4 · Bank subsidiary

Selected financial information

American Savings Bank, F.S.B. and Subsidiaries

Consolidated Statements of Income Data (unaudited)

	Three months ended June 30				Six months ended June 30
(in thousands)	2011		2010		2011		2010
Interest and dividend income
Interest and fees on loans	$	45,648	$	49,328	$	91,745	$	99,073
Interest and dividends on investment and mortgage-related securities	3,793		3,646		7,562		6,963
Total interest and dividend income	49,441		52,974		99,307		106,036
Interest expense
Interest on deposit liabilities	2,387		3,852		4,980		8,275
Interest on other borrowings	1,382		1,418		2,749		2,844
Total interest expense	3,769		5,270		7,729		11,119
Net interest income	45,672		47,704		91,578		94,917
Provision for loan losses	2,555		990		7,105		6,349
Net interest income after provision for loan losses	43,117		46,714		84,473		88,568
Noninterest income
Fee income on deposit liabilities	4,599		7,891		9,048		15,411
Fees from other financial services	7,240		6,649		14,186		13,063
Fee income on other financial products	1,861		1,735		3,534		3,260
Other income	3,177		2,383		5,556		4,776
Total noninterest income	16,877		18,658		32,324		36,510
Noninterest expense
Compensation and employee benefits	18,166		18,907		35,671		36,309
Occupancy	4,288		4,216		8,528		8,441
Data processing	2,058		4,564		4,028		8,902
Services	1,949		1,845		3,720		3,573
Equipment	1,772		1,640		3,429		3,349
Other expense	7,955		8,453		15,888		17,021
Total noninterest expense	36,188		39,625		71,264		77,595
Income before income taxes	23,806		25,747		45,533		47,483
Income taxes	8,611		9,616		16,487		17,616
Net income	$	15,195	$	16,131	$	29,046	$	29,867

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American Savings Bank, F.S.B. and Subsidiaries

Consolidated Balance Sheets Data (unaudited)

(in thousands)	June 30, 2011			December 31, 2010
Assets
Cash and cash equivalents	$	178,251		$	204,397
Federal funds sold	1,249			1,721
Available-for-sale investment and mortgage-related securities	711,347			678,152
Investment in stock of Federal Home Loan Bank of Seattle	97,764			97,764
Loans receivable held for investment, net	3,580,418			3,489,880
Loans held for sale, at lower of cost or fair value	4,784			7,849
Other	234,524			234,806
Goodwill	82,190			82,190
Total assets	$	4,890,527		$	4,796,759
Liabilities and shareholder’s equity
Deposit liabilities—noninterest-bearing	$	912,034		$	865,642
Deposit liabilities—interest-bearing	3,142,915			3,109,730
Other borrowings	239,122			237,319
Other	99,260			90,683
Total liabilities	4,393,331			4,303,374
Common stock	331,348			330,562
Retained earnings	170,157			169,111
Accumulated other comprehensive loss, net of tax benefits	(4,309		)	(6,288		)
Total shareholder’s equity	497,196			493,385
Total liabilities and shareholder’s equity	$	4,890,527		$	4,796,759

Other assets
Bank-owned life insurance	$	119,671		$	117,565
Premises and equipment, net	56,415			56,495
Prepaid expenses	17,700			18,608
Accrued interest receivable	15,178			14,887
Mortgage-servicing rights	6,854			6,699
Real estate acquired in settlement of loans, net	4,722			4,292
Other	13,984			16,260
	$	234,524		$	234,806

Other liabilities
Accrued expenses	$	13,036		$	16,426
Federal and state income taxes payable	34,167			28,372
Cashier’s checks	26,486			22,396
Advance payments by borrowers	10,061			10,216
Other	15,510			13,273
	$	99,260		$	90,683

Other borrowings consisted of securities sold under agreements to repurchase and advances from the Federal Home Loan Bank (FHLB) of Seattle of $174 million and $65 million, respectively, as of June 30, 2011 and $172 million and $65 million, respectively, as of December 31, 2010.

Bank-owned life insurance is life insurance purchased by ASB on the lives of certain key employees, with ASB as the beneficiary. The insurance is used to fund employee benefits through tax-free income from increases in the cash value of the policies and insurance proceeds paid to ASB upon an insured’s death.

As of June 30, 2011, ASB had total commitments to borrowers for loan commitments and unused lines and letters of credit of $1.3 billion.

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Investment and mortgage-related securities portfolio.

Available-for-sale securities. The book value and aggregate fair value by major security type were as follows:

	June 30, 2011									December 31, 2010
			Gross		Gross			Estimated				Gross		Gross			Estimated
	Amortized		unrealized		unrealized			fair		Amortized		unrealized		unrealized			fair
(in thousands)	cost		gains		losses			value		cost		gains		losses			value

Federal agency obligations	$	292,346	$	1,049	$	(439	)	$	292,956	$	317,945	$	171	$	(2,220	)	$	315,896
Mortgage-related securities — FNMA, FHLMC and GNMA	365,908		10,680		(209		)	376,379		310,711		9,570		(311		)	319,970
Municipal bonds	41,459		568		(15		)	42,012		43,632		7		(1,353		)	42,286
	$	699,713	$	12,297	$	(663	)	$	711,347	$	672,288	$	9,748	$	(3,884	)	$	678,152

The following table details the contractual maturities of available-for-sale securities. All positions with variable maturities (e.g. callable debentures and mortgage-related securities) are disclosed based upon the bond’s contractual maturity.

June 30, 2011 (in thousands)	Amortized Cost		Fair value
Due in one year or less	$	10,800	$	10,830
Due after one year through five years	272,346		273,366
Due after five years through ten years	41,577		41,673
Due after ten years	9,082		9,099
	333,805		334,968
Mortgage-related securities-FNMA,FHLMC and GNMA	365,908		376,379
Total available-for-sale securities	$	699,713	$	711,347

Gross unrealized losses and fair value. The gross unrealized losses and fair values (for securities held in available for sale by duration of time in which positions have been held in a continuous loss position) were as follows:

	Less than 12 months					12 months or more					Total
	Gross unrealized			Fair		Gross unrealized			Fair		Gross unrealized			Fair
(in thousands)	losses			value		losses			value		losses			value
June 30, 2011
Federal agency obligations	$	(439	)	$	39,555	$	—		$	—	$	(439	)	$	39,555
Mortgage-related securities — FNMA, FHLMC and GNMA	(100		)	19,793		(109		)	20,164		(209		)	39,957
Municipal bonds	(15		)	4,540		—			—		(15		)	4,540
	$	(554	)	$	63,888	$	(109	)	$	20,164	$	(663	)	$	84,052
December 31, 2010
Federal agency obligations	$	(2,220	)	$	205,316	$	—		$	—	$	(2,220	)	$	205,316
Mortgage-related securities — FNMA, FHLMC and GNMA	(311		)	30,986		—			—		(311		)	30,986
Municipal bonds	(1,353		)	41,479		—			—		(1,353		)	41,479
	$	(3,884	)	$	277,781	$	—		$	—	$	(3,884	)	$	277,781

The unrealized losses on ASB’s investments in obligations issued by federal agencies were caused by interest rate movements. The contractual terms of these investments do not permit the issuer to settle the securities at a price less than the amortized cost bases of the investments. Because ASB does not intend to sell the securities and has determined it is more likely than not that it will not be required to sell the investments before recovery of their amortized costs bases, which may be at maturity, ASB does not consider these investments to be other-than-temporarily impaired at June 30, 2011.

The fair values of ASB’s investment securities could decline if interest rates rise or spreads widen.

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Allowance for loan losses. ASB must maintain an allowance for loan losses that is adequate to absorb estimated probable credit losses associated with its loan portfolio. The allowance for loan losses consists of an allocated portion, which estimates credit losses for specifically identified loans and pools of loans, and an unallocated portion.

The allowance for loan losses was comprised of the following:

				Commercial		Home
	Residential			real		equity line			Residential			Commercial			Residential			Commercial			Consumer
(in thousands)	1-4 family			estate		of credit			land			construction			construction			loans			loans			Unallocated			Total
June 30, 2011
Allowance for loan losses:
Beginning balance	$	6,497		$	1,474	$	4,269		$	6,411		$	1,714		$	7		$	16,015		$	3,325		$	934		$	40,646
Charge-offs	(2,695		)	—		(362		)	(2,790		)	—			—			(1,773		)	(1,518		)	—			(9,138		)
Recoveries	33			—		4			19			—			—			300			314			—			670
Provision	3,694			168		(695		)	1,385			15			(2		)	327			1,350			863			7,105
Ending balance	$	7,529		$	1,642	$	3,216		$	5,025		$	1,729		$	5		$	14,869		$	3,471		$	1,797		$	39,283
Ending balance: individually evaluated for impairment	$	230		$	—	$	—		$	3,067		$	—		$	—		$	1,923		$	—		$	—		$	5,220
Ending balance: collectively evaluated for impairment	$	7,299		$	1,642	$	3,216		$	1,958		$	1,729		$	5		$	12,946		$	3,471		$	1,797		$	34,063

Financing Receivables:
Ending balance	$	2,028,502		$	321,967	$	466,783		$	51,901		$	38,419		$	3,738		$	640,221		$	83,059		$	—		$	3,634,590
Ending balance: individually evaluated for impairment	$	30,816		$	13,543	$	1,263		$	41,268		$	—		$	—		$	54,620		$	25		$	—		$	141,535
Ending balance: collectively evaluated for impairment	$	1,997,686		$	308,424	$	465,520		$	10,633		$	38,419		$	3,738		$	585,601		$	83,034		$	—		$	3,493,055

December 31, 2010
Allowance for loan losses:
Beginning balance	$	5,522		$	861	$	4,679		$	4,252		$	3,068		$	19		$	19,498		$	2,590		$	1,190		$	41,679
Charge-offs	(6,142		)	—		(2,517		)	(6,487		)	—			—			(6,261		)	(3,408		)	—			(24,815		)
Recoveries	744			—		63			63			—			—			1,537			481			—			2,888
Provision	6,373			613		2,044			8,583			(1,354		)	(12		)	1,241				3,662		(256		)	20,894
Ending balance	$	6,497		$	1,474	$	4,269		$	6,411		$	1,714		$	7		$	16,015		$	3,325		$	934		$	40,646
Ending balance: individually evaluated for impairment	$	230		$	—	$	—		$	1,642		$	—		$	—		$	1,588		$	—		$	—		$	3,460
Ending balance: collectively evaluated for impairment	$	6,267		$	1,474	$	4,269		$	4,769		$	1,714		$	7		$	14,427		$	3,325		$	934		$	37,186

Financing Receivables:
Ending balance	$	2,087,813		$	300,689	$	416,453		$	65,599		$	38,079		$	5,602		$	551,683		$	80,138		$	—		$	3,546,056
Ending balance: individually evaluated for impairment	$	34,615		$	12,156	$	827		$	39,631		$	—		$	—		$	28,886		$	76		$	—		$	116,191
Ending balance: collectively evaluated for impairment	$	2,053,198		$	288,533	$	415,626		$	25,968		$	38,079		$	5,602		$	522,797		$	80,062		$	—		$	3,429,865

Credit quality. ASB performs an internal loan review and grading on an ongoing basis. The review provides management with periodic information as to the quality of the loan portfolio and effectiveness of its lending policies and procedures. The objectives of the loan review and grading procedures are to identify, in a timely manner, existing or emerging credit quality problems so that appropriate steps can be initiated to avoid or minimize future losses. Loans subject to grading include commercial, commercial real estate and commercial construction loans.

A ten-point risk rating system is used to determine loan grade and is based on borrower loan risk. The risk rating is a numerical representation of risk based on the overall assessment of the borrower’s financial and operating strength including earnings, operating cash flow, debt service capacity, asset and liability structure, competitive issues, experience and quality of management, financial reporting issues and industry/economic factors.

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The loan grade categories are:

1- Substantially risk free		6- Acceptable risk
2- Minimal risk		7- Special mention
3- Modest risk		8- Substandard
4- Better than average risk		9- Doubtful
5- Average risk		10- Loss

Grades 1 through 6 are considered pass grades. Pass exposures generally are well protected by the current net worth and paying capacity of the obligor or by the value of the asset or underlying collateral.

The credit risk profile by internally assigned grade for loans was as follows:

	June 30, 2011						December 31, 2010
(in thousands)	Commercial real estate		Commercial construction		Commercial		Commercial real estate		Commercial construction		Commercial
Grade:
Pass	$	305,260	$	38,419	$	557,463	$	285,624	$	38,079	$	462,078
Special mention	1,056		—		23,820		526		—		44,759
Substandard	15,651		—		56,795		14,539		—		44,259
Doubtful	—		—		1,978		—		—		556
Loss	—		—		165		—		—		31
Total	$	321,967	$	38,419	$	640,221	$	300,689	$	38,079	$	551,683

The credit risk profile based on payment activity for loans was as follows:

(in thousands)	30-59 days past due		60-89 days past due		Greater than 90 days		Total past due		Current		Total financing receivables		Recorded Investment> 90 days and accruing

June 30, 2011
Real estate loans:
Residential 1-4 family	$	4,775	$	2,837	$	34,942	$	42,554	$	1,985,948	$	2,028,502	$	—
Commercial real estate	—		—		—		—		321,967		321,967		—
Home equity line of credit	993		729		1,492		3,214		463,569		466,783		—
Residential land	968		834		14,027		15,829		36,072		51,901		—
Commercial construction	—		—		—		—		38,419		38,419		—
Residential construction	—		—		—		—		3,738		3,738		—
Commercial loans	1,400		1,667		2,837		5,904		634,317		640,221		60
Consumer loans	483		280		615		1,378		81,681		83,059		442
Total loans	$	8,619	$	6,347	$	53,913	$	68,879	$	3,565,711	$	3,634,590	$	502

December 31, 2010
Real estate loans:
Residential 1-4 family	$	8,245	$	3,719	$	36,419	$	48,383	$	2,039,430	$	2,087,813	$	—
Commercial real estate	—		4		—		4		300,685		300,689		—
Home equity line of credit	1,103		227		1,659		2,989		413,464		416,453		—
Residential land	1,543		1,218		16,060		18,821		46,778		65,599		581
Commercial construction	—		—		—		—		38,079		38,079		—
Residential construction	—		—		—		—		5,602		5,602		—
Commercial loans	892		1,317		3,191		5,400		546,283		551,683		64
Consumer loans	629		410		617		1,656		78,482		80,138		320
Total loans	$	12,412	$	6,895	$	57,946	$	77,253	$	3,468,803	$	3,546,056	$	965

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The credit risk profile based on nonaccrual loans, accruing loans 90 days or more past due and troubled debt restructured loans was as follows:

	June 30, 2011						December 31, 2010
(in thousands)	Nonaccrual loans		Accruing loans 90 days or more past due		Trouble debt restructured loans		Nonaccrual loans		Accruing loans 90 days or more past due		Trouble debt restructured loans

Real estate loans:
Residential 1-4 family	$	34,942	$	—	$	4,938	$	36,420	$	—	$	5,150
Commercial real estate	—		—		—		—		—		1,963
Home equity line of credit	1,492		—		—		1,659		—		—
Residential land	16,022		—		25,857		15,479		581		27,689
Commercial construction	—		—		—		—		—		—
Residential construction	—		—		—		—		—		—
Commercial loans	5,442		60		26,203		4,956		64		4,035
Consumer loans	210		442		—		341		320		—
Total	$	58,108	$	502	$	56,998	$	58,855	$	965	$	38,837

The total carrying amount and the total unpaid principal balance of impaired loans were as follows:

	June 30, 2011						Three months ended June 30, 2011				Six months ended June 30, 2011
(in thousands)	Recorded investment		Unpaid principal balance		Related Allowance		Average recorded investment		Interest income recognized		Average recorded investment		Interest income recognized

With no related allowance recorded
Real estate loans:
Residential 1-4 family	$	20,771	$	28,523	$	—	$	20,000	$	68	$	19,848	$	128
Commercial real estate	13,543		13,543		—		12,396		183		11,276		331
Home equity line of credit	543		1,422		—		654		1		615		1
Residential land	32,310		40,526		—		32,092		420		33,177		939
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	43,665		43,665		—		39,419		702		37,284		1,361
Consumer loans	—		—		—		—		—		—		—
	110,832		127,679		—		104,561		1,374		102,200		2,760
With an allowance recorded
Real estate loans:
Residential 1-4 family	3,884		3,884		230		3,890		49		3,898		109
Commercial real estate	—		—		—		—		—		—		—
Home equity line of credit	—		—		—		—		—		—		—
Residential land	8,748		8,808		3,067		8,482		146		7,363		316
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	10,955		10,955		1,923		8,418		130		7,179		230
Consumer loans	—		—		—		—		—		—		—
	23,587		23,647		5,220		20,790		325		18,440		655
Total
Real estate loans:
Residential 1-4 family	24,655		32,407		230		23,890		117		23,746		237
Commercial real estate	13,543		13,543		—		12,396		183		11,276		331
Home equity line of credit	543		1,422		—		654		1		615		1
Residential land	41,058		49,334		3,067		40,574		566		40,540		1,255
Commercial construction	—		—		—		—		—		—		—
Residential construction	—		—		—		—		—		—		—
Commercial loans	54,620		54,620		1,923		47,837		832		44,463		1,591
Consumer loans	—		—		—		—		—		—		—
	$	134,419	$	151,326	$	5,220	$	125,351	$	1,699	$	120,640	$	3,415

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	December 31, 2010						2010
(in thousands)	Recorded investment		Unpaid principal balance		Related allowance		Average recorded investment		Interest income recognized

With no related allowance recorded
Real estate loans:
Residential 1-4 family	$	18,205	$	24,692	$	—	$	14,609	$	278
Commercial real estate	12,156		12,156		—		14,276		979
Home equity line of credit	—		—		—		—		—
Residential land	33,777		40,802		—		29,914		1,499
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	22,041		22,041		—		29,636		1,846
Consumer loans	—		—		—		—		—
	86,179		99,691		—		88,435		4,602
With an allowance recorded
Real estate loans:
Residential 1-4 family	3,917		3,917		230		2,807		175
Commercial real estate	—		—		—		—		—
Home equity line of credit	—		—		—		—		—
Residential land	5,041		5,090		1,642		3,753		327
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	6,845		6,845		1,588		2,796		182
Consumer loans	—		—		—		—		—
	15,803		15,852		3,460		9,356		684
Total
Real estate loans:
Residential 1-4 family	22,122		28,609		230		17,416		453
Commercial real estate	12,156		12,156		—		14,276		979
Home equity line of credit	—		—		—		—		—
Residential land	38,818		45,892		1,642		33,667		1,826
Commercial construction	—		—		—		—		—
Residential construction	—		—		—		—		—
Commercial loans	28,886		28,886		1,588		32,432		2,028
Consumer loans	—		—		—		—		—
	$	101,982	$	115,543	$	3,460	$	97,791	$	5,286

Litigation. In March 2011, a purported class action lawsuit was filed by a customer who claimed that ASB had improperly charged overdraft fees on debit card transactions. Management is evaluating the merits of the claims alleged in the lawsuit, which is in its preliminary stage. Thus, the outcome is not determinable.

5 · Retirement benefits

Retirement benefit plan changes. On March 11, 2011, the utilities’ union members ratified a new benefit agreement, which included changes to retirement benefits. Changes to retirement benefits for HEI and utility employees commencing employment after April 30, 2011 include a reduction of benefits provided through the defined benefit plan (the Retirement Plan for Employees of Hawaiian Electric Industries, Inc. and Participating Subsidiaries) and the addition of a 50% match by the applicable employer on the first 6% of employee deferrals through the defined contribution plan (under the Hawaiian Electric Industries Retirement Savings Plan (HEIRSP)). In addition, new eligibility rules and contribution levels applicable to existing and new HEI and utility employees were adopted for postretirement welfare benefits. In general, defined pension benefits are based on the employees’ years of service and compensation.

Defined benefit plans. For the six months of 2011, HEI contributed $0.5 million (unconsolidated) to its retirement benefit plans, compared to $0.4 million in the first six months of 2010. HEI’s current estimate of contributions to its

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retirement benefit plans in 2011 is $2 million (unconsolidated), compared to $1 million in 2010. In addition, HEI expects to pay directly $1 million (unconsolidated) of benefits in 2011, comparable to 2010. For a discussion of HECO’s 2011 estimated contributions to the retirement benefit plans, see Note 4, “Retirement benefits,” of HECO’s Notes to Consolidated Financial Statements.

The components of net periodic benefit cost for consolidated HEI were as follows:

	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2011			2010			2011			2010			2011			2010			2011			2010

Service cost	$	8,824		$	7,095		$	1,173		$	1,168		$	17,741		$	14,048		$	2,440		$	2,291
Interest cost	16,271			16,093			2,417			2,652			32,580			32,133			4,878			5,336
Expected return on plan assets	(17,172		)	(17,221		)	(2,657		)	(2,766		)	(34,273		)	(34,415		)	(5,305		)	(5,518		)
Amortization of unrecognized transition obligation	—			—			—			—			1			1			—			—
Amortization of prior service gain	(97		)	(97		)	(309		)	(52		)	(194		)	(194		)	(533		)	(104		)
Recognized actuarial loss (gain)	4,314			1,791			40			(2		)	8,719			3,507			55			(3		)
Net periodic benefit cost	12,140			7,661			664			1,000			24,574			15,080			1,535			2,002
Impact of PUC D&Os	(556		)	2,020			1,734			1,333			(2,100		)	5,028			2,752			2,621
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	11,584		$	9,681		$	2,398		$	2,333		$	22,474		$	20,108		$	4,287		$	4,623

Consolidated HEI recorded retirement benefits expense of $20 million and $19 million in the first six months of 2011 and 2010, respectively, and charged the remaining amounts primarily to electric utility plant.

Defined contribution plans. For the first six months of 2011 and 2010, ASB’s expense for its employees participating in the ASB 401(k) Plan was $1.7 million and $1.9 million, respectively. For the first six months of both 2011 and 2010, ASB’s cash contributions to the plan were $2.8 million.

For the first six months of 2011, the Company’s expense for matching contributions under the HEIRSP was immaterial.

6 · Share-based compensation

Under the 2010 Equity and Incentive Plan (EIP), HEI can issue an aggregate of 4 million shares of common stock as incentive compensation to selected employees in the form of stock options, stock appreciation rights, restricted shares, restricted stock units, performance shares and other share-based and cash-based awards.

Through June 30, 2011, grants under the EIP consisted of 18,009 restricted shares (counted against the shares authorized for issuance under EIP as four shares for every share issued, or 72,036 shares), 162,517 restricted stock units (which will be counted against the shares authorized for issuance under EIP as four shares for every share issued when issued or 650,068 shares) and 371,957 shares that may be issued under the 2011-2013 long-term incentive plan (LTIP) at maximum levels.

Under the 1987 Stock Option and Incentive Plan, as amended (SOIP), grants and awards of an estimated 0.8 million shares of common stock (based on various assumptions, including LTIP awards at maximum levels and the use of the June 30, 2011 market price of shares as the price on the exercise/payment dates) were outstanding as of June 30, 2011 to selected employees in the form of nonqualified stock options (NQSOs), stock appreciation rights (SARs), restricted stock units, LTIP performance and other shares and dividend equivalents. As of May 11, 2010, no new awards may be granted under the SOIP. After the shares of common stock for the outstanding SOIP grants and awards are issued or such grants and awards expire, the remaining shares registered under the SOIP will be deregistered and delisted.

The Company’s share-based compensation expense and related income tax benefit were as follows:

	Three months ended June 30		Six months ended June 30
(dollars in millions)	2011	2010	2011	2010

Share-based compensation expense (1)	0.5	0.8	1.7	1.4
Income tax benefit	0.1	0.2	0.5	0.4

(1) The Company has not capitalized any share-based compensation cost.

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Nonqualified stock options. Information about HEI’s NQSOs was as follows:

June 30, 2011

			Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices		Number of options	Weighted-average remaining contractual life	Weighted-average exercise price

2002	$	21.68	20,000	0.8	$	21.68
2003	20.49		93,500	1.7	20.49
	$	20.49 – 21.68	113,500	1.5	$	20.70

As of December 31, 2010, NQSOs outstanding totaled 215,500 (representing the same number of underlying shares), with a weighted-average exercise price of $20.76. As of June 30, 2011, all NQSOs outstanding were exercisable and had an aggregate intrinsic value (including dividend equivalents) of $0.7 million.

NQSO activity and statistics were as follows:

	Three months ended June 30				Six months ended June 30
(dollars in thousands, except prices)	2011		2010		2011		2010

Shares expired	—		—		—		2,000
Weighted-average price of shares expired	—		—		—		$	20.49
Shares exercised	69,500		17,000		102,000		63,000
Weighted-average exercise price	$	21.07	$	20.34	$	20.82	$	16.25
Cash received from exercise	$	1,465	$	346	$	2,123	$	1,024
Intrinsic value of shares exercised (1)	$	581	$	76	$	840	$	625
Tax benefit realized for the deduction of exercises	$	170	$	29	$	271	$	243

(1) Intrinsic value is the amount by which the fair market value of the underlying stock and the related dividend equivalents exceeds the exercise price of the option.

Stock appreciation rights. Information about HEI’s SARs was as follows:

June 30, 2011

			Outstanding & Exercisable (Vested)
Year of grant	Range of exercise prices		Number of shares underlying SARs	Weighted-average remaining contractual life	Weighted-average exercise price

2004	$	26.02	132,000	1.8	$	26.02
2005	26.18		278,000	2.5	26.18
	$	26.02 –26.18	410,000	2.3	$	26.13

As of December 31, 2010, the shares underlying SARs outstanding totaled 450,000, with a weighted-average exercise price of $26.13. As of June 30, 2011, all SARs outstanding were exercisable and had no intrinsic value.

SARs activity and statistics were as follows:

	Three months ended June 30				Six months ended June 30
(dollars in thousands, except prices)	2011		2010		2011		2010

Shares forfeited	—		—		—		—
Weighted-average price of shares forfeited	—		—		—		—
Shares expired	4,000		12,000		40,000		18,000
Weighted-average price of shares expired	$	26.18	$	26.18	$	26.11	$	26.18
Shares exercised	—		—		—		—

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Restricted shares and restricted stock awards. Information about HEI’s grants of restricted shares and restricted stock awards was as follows:

	Three months ended June 30								Six months ended June 30
	2011				2010				2011				2010
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	88,709		$	24.63	120,700		$	25.48	89,709		$	24.64	129,000		$	25.50
Granted	—		—		—		—		—		—		—		—
Vested	(29,800	)	26.03		(42,000	)	26.30		(29,800	)	26.03		(43,565	)	26.29
Forfeited	(1,000	)	24.68		—		—		(2,000	)	25.02		(6,735	)	25.75
Outstanding, end of period	57,909		$	23.91	78,700		$	25.04	57,909		$	23.91	78,700		$	25.04

(1) Weighted-average grant-date fair value per share. The grant date fair value of a restricted stock award share was the closing or average price of HEI common stock on the date of grant.

For the second quarters of 2011 and 2010, total restricted stock vested had a fair value of $0.8 million and $1.1 million, respectively. For the six months ended June 30, 2011 and 2010, total restricted stock vested had a fair value of $0.8 million and $1.1 million, respectively. The tax benefits realized for the tax deductions related to restricted stock awards were $0.1 million and $0.3 million for the first six months of 2011 and 2010, respectively.

As of June 30, 2011, there was $0.4 million of total unrecognized compensation cost related to nonvested restricted shares and restricted stock awards. The cost is expected to be recognized over a weighted-average period of 2.6 years.

Restricted stock units. Information about HEI’s grants of restricted stock units was as follows:

	Three months ended June 30								Six months ended June 30
	2011				2010				2011				2010
	Shares		(1)		Shares		(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	230,517		$	21.69	69,000		$	16.99	146,500		$	19.80	70,500		$	16.99
Granted	1,000	(2)	26.25		77,500	(4)	22.30		86,017	(3)	24.97		77,500	(4)	22.30
Vested	—		—		—		—		—		—		(250	)	16.99
Forfeited	—		—		—		—		(1,000	)	22.60		(1,250	)	16.99
Outstanding, end of period	231,517		$	21.70	146,500		$	19.80	231,517		$	21.70	146,500		$	19.80

(1) Weighted-average grant-date fair value per share. The grant date fair value of the restricted stock units was the average price of HEI common stock on the date of grant.

(2) Total weighted-average grant date fair value of $26,000.

(3) Total weighted-average grant-date fair value of $2.1 million.

(4) Total weighted-average grant-date fair value of $1.7 million

As of June 30, 2011, there was $3.2 million of total unrecognized compensation cost related to the nonvested restricted stock units. The cost is expected to be recognized over a weighted-average period of 3.0 years.

LTIP payable in stock. The 2011-2013 LTIP provides for performance awards under the EIP and the 2009-2011 LTIP and the 2010-2012 LTIP provide for performance awards under the SOIP of shares of HEI common stock based on the satisfaction of performance goals and service conditions over a three-year performance period. The number of shares of HEI common stock that may be awarded is fixed on the date the grants are made subject to the achievement of specified performance levels. The payout varies from 0% to 200% of the number of target shares depending on achievement of the goals. The LTIP performance goals for both LTIP periods include awards with a market goal based on total return to shareholders (TRS) of HEI stock as a percentile to the Edison Electric Institute Index over the applicable three-year period. In addition, the 2009-2011 LTIP has performance goals based on HEI return on average common equity (ROACE), the 2010-2012 LTIP has performance goals related to levels of HEI consolidated net income, HECO consolidated ROACE, ASB net income and ASB return on assets — all based on two-year averages (2011-2012), and the 2011-2013 LTIP has performance goals related to levels of HEI consolidated net income, HECO consolidated ROACE, HECO 3-year average consolidated net income, ASB return on assets and ASB 3-year average net income.

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LTIP linked to TRS. Information about HEI’s LTIP grants linked to TRS was as follows:

	Three months ended June 30							Six months ended June 30
	2011				2010			2011				2010
	Shares		(1)		Shares	(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	200,735		$	25.94	132,588	$	20.42	126,782		$	20.33	36,198		$	14.85
Granted	475		35.46		—	—		75,015	(2)	35.46		97,191	(3)	22.45
Vested	—		—		—	—		—		—		—		—
Forfeited	(1,647	)	22.45		—	—		(2,234	)	22.45		(801	)	14.85
Outstanding, end of period	199,563		$	25.99	132,588	$	20.42	199,563		$	25.99	132,588		$	20.42

(1) Weighted-average grant-date fair value per share determined using a Monte Carlo simulation model.

(2) Total weighted-average grant-date fair value of $2.7 million.

(3) Total weighted-average grant-date fair value of $2.2 million.

On May 12, 2011, LTIP grants (under the 2011-2013 LTIP) were made payable in 475 shares of HEI common stock (based on the grant date price of $26.25 and target TRS performance levels) with a weighted-average grant date fair value of $17,000 based on the weighted-average grant date fair value per share of $35.46.

The assumptions used to determine the fair value of the LTIP linked to TRS and the resulting fair value of LTIP granted were as follows:

	2011	2010
Risk-free interest rate	1.25%	1.30%
Expected life in years	3	3
Expected volatility	27.8%	27.9%
Range of expected volatility for Peer Group	21.2% to 82.6%	22.3% to 52.3%
Grant date fair value (per share)	$35.46	$22.45

As of June 30, 2011, there was $3.1 million of total unrecognized compensation cost related to the nonvested performance awards payable in shares linked to TRS. The cost is expected to be recognized over a weighted-average period of 1.7 years.

LTIP linked to other performance conditions. Information about HEI’s LTIP awards payable in shares linked to other performance conditions was as follows:

	Three months ended June 30							Six months ended June 30
	2011				2010			2011				2010
	Shares		(1)		Shares	(1)		Shares		(1)		Shares		(1)

Outstanding, beginning of period	273,550		$	21.26	184,535	$	18.69	161,310		$	18.66	24,131		$	16.99
Granted	712		26.25		—	—		113,831	(2)	24.96		160,939	(3)	18.95
Vested	—		—		—	—		—		—		—		—
Cancelled	(81,908	)	18.38		—	—		(81,908	)	18.38		—		—
Forfeited	(6,587	)	18.95		—	—		(7,466	)	18.95		(535	)	16.99
Outstanding, end of period	185,767		$	22.63	184,535	$	18.69	185,767		$	22.63	184,535		$	18.69

(1) Weighted-average grant-date fair value per share based on the average price of HEI common stock on the date of grant.

(2) Total weighted-average grant-date fair value of $2.8 million.

(3) Total weighted-average grant-date fair value of $3.0 million.

On May 12, 2011, LTIP grants (under the 2011-2013 LTIP) were made payable in 712 shares of HEI common stock (based on the grant date price of $26.25 and target performance levels relating to performance goals other than TRS), with a weighted-average grant date fair value of $19,000 based on the weighted-average grant date fair value per share of $26.25.

As of June 30, 2011, there was $3.1 million of total unrecognized compensation cost related to the nonvested shares linked to performance conditions other than TRS. The cost is expected to be recognized over a weighted-average period of 2.1 years.

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7 · Interest rate swap agreements

In June 2010, HEI entered into multiple Forward Starting Swaps (FSS) with notional amounts totaling $125 million to hedge against interest rate fluctuations on medium-term notes expected to be issued by HEI in 2011, thereby enabling HEI to better forecast its future interest expense. The FSS entitled HEI to receive/(pay) the present value of the positive/(negative) difference between three-month LIBOR and a fixed rate at termination applied to the notional amount over a five-year period. The outstanding FSS were designated and accounted for as cash flow hedges and had a negative fair value of $2.8 million as of December 31, 2010 (recorded in “Other” liabilities). Changes in fair value were recognized (1) in other comprehensive income to the extent that they are considered effective, and (2) in “Interest expense—other than on deposit liabilities and other bank borrowings” for any portion considered ineffective.

In the first six months of 2011, HEI settled the FSS for payments totaling $5.2 million, of which $3.3 million was the ineffective portion ($0.8 million and $2.5 million recognized in 2010 and 2011, respectively) and $1.9 million is being amortized to interest expense over five years beginning March 24, 2011 (the date that HEI issued $125 million of Senior Notes via a private placement—$75 million of 4.41% notes due March 24, 2016 and $50 million of 5.67% notes due March 24, 2021).

8 · Earnings per share (EPS)

For the three and six months ended June 30, 2011, under the two-class method of computing basic and diluted EPS, distributed earnings were $0.31 and $0.62 per share, respectively, and undistributed losses were $(0.03) and $(0.04) per share, respectively, for both unvested restricted stock awards and unrestricted common stock. For the three and six months ended June 30, 2010, under the two-class method of computing basic and diluted EPS, distributed earnings were $0.31 and $0.62 per share, respectively, and undistributed losses were nil and $(0.01) per share, respectively, for both unvested restricted stock awards and unrestricted common stock.

As of June 30, 2011 and 2010, the antidilutive effects of SARs of 410,000 shares and 462,000 shares of HEI common stock, respectively, for which the exercise prices were greater than the closing market price of HEI’s common stock were not included in the computation of diluted EPS.

9 · Commitments and contingencies

See Note 4, “Bank subsidiary,” above and Note 5, “Commitments and contingencies,” of HECO’s “Notes to Consolidated Financial Statements,” below.

10 · Fair value measurements

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the Company uses its own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the Company were to sell its entire holdings of a particular financial instrument at one time. Because no active trading market exists for a portion of the Company’s financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in making such estimates.

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The Company used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and cash equivalents and short term borrowings—other than bank. The carrying amount approximated fair value because of the short maturity of these instruments.

Investment and mortgage-related securities. Fair value was based on observable inputs using market-based valuation techniques.

Loans receivable. For residential real estate loans, fair value was calculated by discounting estimated cash flows using discount rates based on current industry pricing for loans with similar contractual characteristics.

For other types of loans, fair value was estimated by discounting contractual cash flows using discount rates that reflect current industry pricing for loans with similar characteristics and remaining maturity. Where industry pricing is not available, discount rates are based on ASB’s current pricing for loans with similar characteristics and remaining maturity.

The fair value of all loans was adjusted to reflect current assessments of loan collectability.

Deposit liabilities. The fair value of savings, negotiable orders of withdrawal, demand and money market deposits was the amount payable on demand at the reporting date. The fair value of fixed-maturity certificates of deposit was estimated by discounting the future cash flows using the rates currently offered for deposits of similar remaining maturities.

Other bank borrowings. Fair value was estimated by discounting the future cash flows using the current rates available for borrowings with similar credit terms and remaining maturities.

Long-term debt. Fair value was obtained from a third-party financial services provider or the BLOOMBERG PROFESSIONAL service based on the current rates offered for debt of the same or similar remaining maturities.

Forward Starting Swaps. Fair value was estimated by discounting the expected future cash flows of the swaps, using the contractual terms of the swaps, including the period to maturity, and observable market-based inputs, including forward interest rate curves. Fair value incorporates credit valuation adjustments to appropriately reflect nonperformance risk.

Off-balance sheet financial instruments. The fair value of loans serviced for others was calculated by discounting expected net income streams using discount rates that reflect industry pricing for similar assets. Expected net income streams were estimated based on industry assumptions regarding prepayment speeds and income and expenses associated with servicing residential mortgage loans for others. The fair value of commitments to originate loans was estimated based on the change in current primary market prices of new commitments. Since lines of credit can expire without being drawn and customers are under no obligation to utilize the lines, no fair value was assigned to unused lines of credit. The fair value of letters of credit was estimated based on the fees currently charged to enter into similar agreements, taking into account the remaining terms of the agreements. The fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

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The estimated fair values of certain of the Company’s financial instruments were as follows:

	June 30, 2011				December 31, 2010
(in thousands)	Carrying or notional amount		Estimated fair value		Carrying or notional amount		Estimated fair value

Financial assets
Cash and cash equivalents, excluding money market accounts	$	180,900	$	180,900	$	329,553	$	329,553
Money market accounts	85,846		85,846		1,098		1,098
Available-for-sale investment and mortgage-related securities	711,347		711,347		678,152		678,152
Investment in stock of Federal Home Loan Bank of Seattle	97,764		97,764		97,764		97,764
Loans receivable, net	3,585,202		3,756,997		3,497,729		3,639,983
Financial liabilities
Deposit liabilities	4,054,949		4,058,762		3,975,372		3,979,027
Short-term borrowings—other than bank	—		—		24,923		24,923
Other bank borrowings	239,122		253,291		237,319		251,822
Long-term debt, net—other than bank	1,440,006		1,411,318		1,364,942		1,345,770
Forward starting swaps	—		—		2,762		2,762
Off-balance sheet items
HECO-obligated preferred securities of trust subsidiary	50,000		50,040		50,000		52,500

As of June 30, 2011 and December 31, 2010, loan commitments and unused lines and letters of credit issued by ASB had notional amounts of $1.3 billion and $1.2 billion, respectively, and their estimated fair value on such dates were $0.2 million and $0.4 million, respectively. As of June 30, 2011 and December 31, 2010, loans serviced by ASB for others had notional amounts of $849 million and $818 million and the estimated fair value of the servicing rights for such loans was $9.6 million and $8.8 million, respectively.

Fair value measurements on a recurring basis. While securities held in ASB’s investment portfolio trade in active markets, they do not trade on listed exchanges nor do the specific holdings trade in quoted markets by dealers or brokers. All holdings are valued using market-based approaches that are based on exit prices that are taken from identical or similar market transactions, even in situations where trading volume may be low when compared with prior periods as has been the case during the recent market disruption. Inputs to these valuation techniques reflect the assumptions that consider credit and nonperformance risk that market participants would use in pricing the asset based on market data obtained from independent sources. Available-for-sale securities were comprised of federal agency obligations and mortgage-backed securities and municipal bonds.

Assets and liabilities measured at fair value on a recurring basis were as follows:

	Fair value measurements using
	Quoted prices in active		Significant other			Significant
	markets for identical		observable			Unobservable
(in thousands)	assets (Level 1)		inputs (Level 2)			inputs (Level 3)
June 30, 2011
Money market accounts (electric utility and “other” segments)	$	—	$	85,846		$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	376,379		$	—
Federal agency obligations	—		292,956			—
Municipal bonds	—		42,012			—
	$	—	$	711,347		$	—
December 31, 2010
Money market accounts (“other” segment)	$	—	$	1,098		$	—
Available-for-sale securities (bank segment)
Mortgage-related securities-FNMA, FHLMC and GNMA	$	—	$	319,970		$	—
Federal agency obligations	—		315,896			—
Municipal bonds	—		42,286			—
	$	—	$	678,152		$	—
Forward starting swaps (“other” segment)	$	—	$	(2,762	)	$	—

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Fair value measurements on a nonrecurring basis. From time to time, the Company may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the write-downs of individual assets. ASB does not record loans at fair value on a recurring basis. However, from time to time, ASB records nonrecurring fair value adjustments to loans to reflect specific reserves on loans based on the current appraised value of the collateral or unobservable market assumptions. Unobservable assumptions reflect ASB’s own estimate of the fair value of collateral used in valuing the loan. ASB may also be required to measure goodwill at fair value on a nonrecurring basis. During the first six months of 2011 and 2010, goodwill was not measured at fair value. For the first six months of 2011 and 2010, there were no adjustments to fair value for assets measured at fair value on a nonrecurring basis in accordance with GAAP other than the specific reserves on loans receivable held for investment.

From time to time, the Company may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of HECO’s asset retirement obligations (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread (also see Note 3).

11 · Cash flows

Supplemental disclosures of cash flow information. For the six months ended June 30, 2011 and 2010, the Company paid interest to non-affiliates amounting to $50 million and $46 million, respectively.

For the six months ended June 30, 2011 and 2010, the Company paid/(received) income taxes amounting to $(21) million and $44 million, respectively. Income taxes were received in 2011 primarily due to the refunding of estimated tax payments made prior to the extension of bonus depreciation provisions.

Supplemental disclosures of noncash activities. Under the HEI Dividend Reinvestment and Stock Purchase Plan (DRIP), common stock dividends reinvested by shareholders in HEI common stock in noncash transactions amounted to $12 million and $11 million for the six months ended June 30, 2011 and 2010, respectively.

Noncash increases in common stock for director and officer compensatory plans of the Company were $5.6 million and $2.3 million for the six months ended June 30, 2011 and 2010, respectively.

Real estate acquired in settlement of loans in noncash transactions amounted to $5 million and $2 million for the six months ended June 30, 2011 and 2010, respectively.

12 · Recent accounting pronouncements and interpretations

Troubled debt restructuring (TDR). In April 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-02, “A Creditor’s Determination of Whether a Restructuring Is a Troubled Debt Restructuring,” which clarifies which loan modifications constitute TDRs and is intended to assist creditors in determining whether a modification of the terms of a receivable meets the criteria to be considered a TDR, both for purposes of recording an impairment loss and for disclosure of TDRs. In evaluating whether a restructuring constitutes a TDR, a creditor must separately conclude that both (a) the restructuring constitutes a concession by the creditor; and (b) the debtor is experiencing financial difficulties. Clarifying guidance is provided on a creditor’s evaluation of whether it has granted a concession and whether a debtor is experiencing financial difficulties.

The Company will adopt this standard in the third quarter of 2011 and does not expect the adoption to have a material impact on the Company’s results of operations, financial condition or liquidity.

Repurchase agreements. In April 2011, the FASB issued ASU No. 2011-03, “Transfers and Servicing (Topic 860): Reconsideration of Effective Control for Repurchase Agreements,” which is intended to improve the financial reporting of repurchase agreements and other agreements that entitle and obligate a transferor to repurchase or redeem financial assets before their maturity. This ASU removes from the assessment of effective control the criterion requiring the transferor to have the ability to repurchase or redeem the financial assets. ASB will apply this guidance prospectively to transactions or modifications of existing transactions that occur on or after January 1, 2012 and does not expect it to have a material impact on the Company’s financial condition, results of operations or liquidity.

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Fair value measurements. In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” which represents the converged guidance of the FASB and the International Accounting Standards Board (the Boards) on fair value measurement. This ASU includes the Boards’ common requirements for measuring fair value and for disclosing information about fair value measurements, including a consistent meaning of the term “fair value.” The Boards have concluded the common requirements will result in greater comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards.

The Company will prospectively adopt this standard in the first quarter of 2012 and does not expect it to have a material impact on the Company’s financial condition, results of operations or liquidity.

Comprehensive income. In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” which eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. All items of net income and other comprehensive income are required to be presented in either a single continuous statement of comprehensive income or in two separate, but consecutive, statements—a net income statement and a total comprehensive income statement.

The Company expects to retrospectively adopt this standard by the first quarter of 2012 using a two-statement approach.

13 · Credit agreement

HEI maintains a revolving noncollateralized credit agreement establishing a line of credit facility of $125 million, with a letter of credit sub-facility, expiring on May 7, 2013, with a syndicate of eight financial institutions. The facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HEI’s short-term and long-term indebtedness, to make investments in or loans to subsidiaries and for HEI’s working capital and general corporate purposes.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Income (unaudited)

	Three months ended June 30						Six months ended June 30
(in thousands)	2011			2010			2011			2010
Operating revenues	$	727,652		$	582,094		$	1,371,953		$	1,128,806
Operating expenses
Fuel oil	312,141			215,322			573,001			427,074
Purchased power	171,737			139,513			319,695			256,295
Other operation	67,388			60,254			132,919			119,498
Maintenance	31,276			32,223			60,472			59,276
Depreciation	36,258			38,649			72,690			77,291
Taxes, other than income taxes	67,152			54,170			127,147			105,961
Income taxes	11,160			11,113			22,770			22,154
	697,112			551,244			1,308,694			1,067,549
Operating income	30,540			30,850			63,259			61,257
Other income
Allowance for equity funds used during construction	1,317			1,847			2,561			3,620
Other, net	898			372			1,808			1,613
	2,215			2,219			4,369			5,233
Interest and other charges
Interest on long-term debt	14,383			14,383			28,766			28,766
Amortization of net bond premium and expense	766			726			1,549			1,393
Other interest charges	636			609			1,175			1,208
Allowance for borrowed funds used during construction	(553		)	(790		)	(1,073		)	(1,569		)
	15,232			14,928			30,417			29,798
Net income	17,523			18,141			37,211			36,692
Preferred stock dividends of subsidiaries	229			229			458			458
Net income attributable to HECO	17,294			17,912			36,753			36,234
Preferred stock dividends of HECO	270			270			540			540
Net income for common stock	$	17,024		$	17,642		$	36,213		$	35,694

HEI owns all of the common stock of HECO. Therefore, per share data with respect to shares of common stock of HECO are not meaningful.

The accompanying notes for HECO are an integral part of these consolidated financial statements.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Balance Sheets (unaudited)

(dollars in thousands, except par value)	June 30, 2011			December 31, 2010
Assets
Utility plant, at cost
Land	$	51,439		$	51,364
Plant and equipment	4,941,887			4,896,974
Less accumulated depreciation	(1,968,207		)	(1,941,059		)
Construction in progress	122,946			101,562
Net utility plant	3,148,065			3,108,841
Current assets
Cash and cash equivalents	25,534			122,936
Customer accounts receivable, net	174,434			138,171
Accrued unbilled revenues, net	122,863			104,384
Other accounts receivable, net	6,425			9,376
Fuel oil stock, at average cost	159,214			152,705
Materials and supplies, at average cost	38,207			36,717
Prepayments and other	41,094			55,216
Regulatory assets	9,982			7,349
Total current assets	577,753			626,854
Other long-term assets
Regulatory assets	468,784			470,981
Unamortized debt expense	13,145			14,030
Other	71,375			64,974
Total other long-term assets	553,304			549,985
Total assets	$	4,279,122		$	4,285,680
Capitalization and liabilities
Capitalization
Common stock ($6 2/3 par value, authorized 50,000,000 shares; outstanding 13,830,823 shares)	$	92,224		$	92,224
Premium on capital stock	389,609			389,609
Retained earnings	855,790			854,856
Accumulated other comprehensive income, net of income taxes	783			709
Common stock equity	1,338,406			1,337,398
Cumulative preferred stock — not subject to mandatory redemption	34,293			34,293
Long-term debt, net	1,000,506			1,057,942
Total capitalization	2,373,205			2,429,633
Current liabilities
Current portion of long-term debt	57,500			—
Accounts payable	140,180			178,959
Interest and preferred dividends payable	20,457			20,603
Taxes accrued	173,811			175,960
Other	57,820			56,354
Total current liabilities	449,768			431,876
Deferred credits and other liabilities
Deferred income taxes	301,503			269,286
Regulatory liabilities	309,809			296,797
Unamortized tax credits	60,143			58,810
Retirement benefits liability	335,874			355,844
Other	109,331			108,070
Total deferred credits and other liabilities	1,116,660			1,088,807
Contributions in aid of construction	339,489			335,364
Total capitalization and liabilities	$	4,279,122		$	4,285,680

The accompanying notes for HECO are an integral part of these consolidated financial statements.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Changes in Common Stock Equity (unaudited)

	Common stock			Premium on capital			Retained			Accumulated other comprehensive
(in thousands)	Shares	Amount		stock			earnings			income (loss)			Total
Balance, December 31, 2010	13,831	$	92,224	$	389,609		$	854,856		$	709		$	1,337,398
Comprehensive income (loss):
Net income for common stock	—	—		—			36,213			—			36,213
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $2,849	—	—		—			—			4,426			4,426
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $2,801	—	—		—			—			(4,352		)	(4,352		)
Other comprehensive income										74
Comprehensive income													36,287
Common stock dividends	—	—		—			(35,279		)	—			(35,279		)
Common stock issue expenses	—	—		—			—			—			—
Balance, June 30, 2011	13,831	$	92,224	$	389,609		$	855,790		$	783		$	1,338,406
Balance, December 31, 2009	13,787	$	91,931	$	385,659		$	827,036		$	1,782		$	1,306,408
Comprehensive income (loss):
Net income for common stock	—	—		—			35,694			—			35,694
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits of $1,155	—	—		—			—			1,813			1,813
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes of $1,080	—	—		—			—			(1,697		)	(1,697		)
Other comprehensive income										116
Comprehensive income													35,810
Common stock dividends	—	—		—			(26,887		)	—			(26,887		)
Common stock issue expenses	—	—		(7		)	—			—			(7		)
Balance, June 30, 2010	13,787	$	91,931	$	385,652		$	835,843		$	1,898		$	1,315,324

The accompanying notes for HECO are an integral part of these consolidated financial statements.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (unaudited)

Six months ended June 30	2011			2010
(in thousands)
Cash flows from operating activities
Net income	$	37,211		$	36,692
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation of property, plant and equipment	72,690			77,291
Other amortization	10,833			3,101
Changes in deferred income taxes	33,456			(4,522		)
Changes in tax credits, net	1,556			1,685
Allowance for equity funds used during construction	(2,561		)	(3,620		)
Decrease in cash overdraft	(2,305		)	(302		)
Changes in assets and liabilities
Increase in accounts receivable	(33,312		)	(18,258		)
Increase in accrued unbilled revenues	(18,479		)	(6,497		)
Increase in fuel oil stock	(6,509		)	(49,759		)
Increase in materials and supplies	(1,490		)	(872		)
Increase in regulatory assets	(14,498		)	(2,252		)
Decrease in accounts payable	(48,288		)	(1,186		)
Changes in prepaid and accrued income taxes and utility revenue taxes	12,178			(31,864		)
Changes in other assets and liabilities	(24,425		)	14,669
Net cash provided by operating activities	16,057			14,306
Cash flows from investing activities
Capital expenditures	(85,395		)	(71,497		)
Contributions in aid of construction	8,153			9,430
Other	77			—
Net cash used in investing activities	(77,165		)	(62,067		)
Cash flows from financing activities
Common stock dividends	(35,279		)	(26,887		)
Preferred stock dividends of HECO and subsidiaries	(998		)	(998		)
Net increase in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	—			14,100
Other	(17		)	(1,349		)
Net cash used in financing activities	(36,294		)	(15,134		)
Net decrease in cash and cash equivalents	(97,402		)	(62,895		)
Cash and cash equivalents, beginning of period	122,936			73,578
Cash and cash equivalents, end of period	$	25,534		$	10,683

The accompanying notes for HECO are an integral part of these consolidated financial statements.

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Hawaiian Electric Company, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1 · Basis of presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with GAAP for interim financial information, the instructions to SEC Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In preparing the financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenues and expenses for the period. Actual results could differ significantly from those estimates. The accompanying unaudited consolidated financial statements and the following notes should be read in conjunction with the audited consolidated financial statements and the notes thereto incorporated by reference in HECO’s Form 10-K for the year ended December 31, 2010 and the unaudited consolidated financial statements and the notes thereto in HECO’s Quarterly Report on SEC Form 10-Q for the quarter ended March 31, 2011.

In the opinion of HECO’s management, the accompanying unaudited consolidated financial statements contain all material adjustments required by GAAP to fairly state the financial position of HECO and its subsidiaries as of June 30, 2011 and December 31, 2010 and the results of their operations for the three and six months ended June 30, 2011 and 2010 and their cash flows for the six months ended June 30, 2011 and 2010. All such adjustments are of a normal recurring nature, unless otherwise disclosed in this Form 10-Q or other referenced material. Results of operations for interim periods are not necessarily indicative of results for the full year. When required, certain reclassifications are made to the prior period’s consolidated financial statements to conform to the current presentation.

2 · Unconsolidated variable interest entities

HECO Capital Trust III. HECO Capital Trust III (Trust III) was created and exists for the exclusive purposes of (i) issuing in March 2004 2,000,000 6.50% Cumulative Quarterly Income Preferred Securities, Series 2004 (2004 Trust Preferred Securities) ($50 million aggregate liquidation preference) to the public and trust common securities ($1.5 million aggregate liquidation preference) to HECO, (ii) investing the proceeds of these trust securities in 2004 Debentures issued by HECO in the principal amount of $31.5 million and issued by Hawaii Electric Light Company, Inc. (HELCO) and Maui Electric Company, Limited (MECO) each in the principal amount of $10 million, (iii) making distributions on these trust securities and (iv) engaging in only those other activities necessary or incidental thereto. The 2004 Trust Preferred Securities are mandatorily redeemable at the maturity of the underlying debt on March 18, 2034, which maturity may be extended to no later than March 18, 2053; and are currently redeemable at the issuer’s option without premium. The 2004 Debentures, together with the obligations of HECO, HELCO and MECO under an expense agreement and HECO’s obligations under its trust guarantee and its guarantee of the obligations of HELCO and MECO under their respective debentures, are the sole assets of Trust III. Trust III has at all times been an unconsolidated subsidiary of HECO. Since HECO, as the common security holder, does not absorb the majority of the variability of Trust III, HECO is not the primary beneficiary and does not consolidate Trust III in accordance with accounting rules on the consolidation of VIEs. Trust III’s balance sheets as of June 30, 2011 and December 31, 2010 each consisted of $51.5 million of 2004 Debentures; $50.0 million of 2004 Trust Preferred Securities; and $1.5 million of trust common securities. Trust III’s income statements for the six months ended June 30, 2011 and 2010 each consisted of $1.7 million of interest income received from the 2004 Debentures, $1.6 million of distributions to holders of the Trust Preferred Securities, and $0.1 million of common dividends on the trust common securities to HECO. So long as the 2004 Trust Preferred Securities are outstanding, HECO is not entitled to receive any funds from Trust III other than pro-rata distributions, subject to certain subordination provisions, on the trust common securities. In the event of a default by HECO in the performance of its obligations under the 2004 Debentures or under its Guarantees, or in the event HECO, HELCO or MECO elect to defer

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payment of interest on any of their respective 2004 Debentures, then HECO will be subject to a number of restrictions, including a prohibition on the payment of dividends on its common stock.

Power purchase agreements. As of June 30, 2011, HECO and its subsidiaries had six PPAs totaling 540 megawatts (MW) of firm capacity and other PPAs with smaller independent power producers (IPPs) and Schedule Q providers (i.e., customers with cogeneration and/or small power production facilities with a capacity of 100 kW or less who buy power from or sell power to the utilities), none of which are currently required to be consolidated as VIEs. Approximately 91% of the 540 MW of firm capacity is pursuant to PPAs, entered into before December 31, 2003, with AES Hawaii, Inc. (AES Hawaii), Kalaeloa Partners, L.P. (Kalaeloa), Hamakua Energy Partners, L.P. (HEP) and HPOWER. Purchases from all IPPs for the six months ended June 30, 2011 totaled $320 million, with purchases from AES Hawaii, Kalaeloa, HEP and HPOWER totaling $71 million, $139 million, $24 million and $30 million, respectively.

Some of the IPPs have provided sufficient information for HECO to determine that the IPP was not a VIE, or was either a “business” or “governmental organization” (e.g., HPOWER), and thus excluded from the scope of accounting standards for VIEs. A windfarm and Kalaeloa provided sufficient information, as required under their PPAs or amendments, such that HECO could determine that consolidation was not required. Management has concluded that the consolidation of some IPPs is not required as HECO and its subsidiaries do not have variable interests in the IPPs because the PPAs do not require them to absorb any variability of the IPPs.

An enterprise with an interest in a VIE or potential VIE created before December 31, 2003 and not thereafter materially modified is not required to apply accounting standards for VIEs to that entity if the enterprise is unable to obtain the necessary information after making an exhaustive effort. HECO and its subsidiaries have made and continue to make exhaustive efforts to get the necessary information, but have been unsuccessful to date as it was not a contractual requirement prior to 2004. If the requested information is ultimately received from these IPPs, a possible outcome of future analyses of such information is the consolidation of one or more of such IPPs. The consolidation of any significant IPP could have a material effect on the Company’s and HECO’s consolidated financial statements, including the recognition of a significant amount of assets and liabilities and the potential recognition of losses. If HECO and its subsidiaries determine they are required to consolidate the financial statements of such an IPP and the consolidation has a material effect, HECO and its subsidiaries would retrospectively apply accounting standards for VIEs.

3 · Revenue taxes

HECO and its subsidiaries’ operating revenues include amounts for various Hawaii state revenue taxes. Revenue taxes are generally recorded as an expense in the period the related revenues are recognized. However, HECO and its subsidiaries’ revenue tax payments to the taxing authorities are based on the prior year’s revenues. For the six months ended June 30, 2011 and 2010, HECO and its subsidiaries included approximately $121 million and $100 million, respectively, of revenue taxes in “operating revenues” and in “taxes, other than income taxes” expense.

4 · Retirement benefits

Retirement benefit plan changes. See “Retirement benefit plan changes” in Note 5 of HEI’s Notes to Consolidated Financial Statements.

Defined benefit plans. For the first six months of 2011, HECO and its subsidiaries contributed $37 million to their retirement benefit plans, compared to $16 million in the first six months of 2010. HECO and its subsidiaries’ current estimate of contributions to their retirement benefit plans in 2011 is $73 million, compared to contributions of $31 million in 2010. The increase in expected 2011 contributions over 2010 contributions is driven by the minimum funding requirements under the Pension Protection Act of 2006, which were impacted by the following three factors: (1) the credit balance available to apply toward satisfaction of the minimum funding requirements was fully depleted in 2010 leaving no credit balance to be applied to 2011, (2) under the Pension Protection Act of 2006, the requirement was to fund 96% of target liability in 2010, which increased to 100% for 2011 and future years, and (3)

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lower interest rates. HECO and its subsidiaries expect to pay directly $1 million of benefits in 2011, comparable to 2010.

The components of net periodic benefit cost were as follows:

	Three months ended June 30												Six months ended June 30
	Pension benefits						Other benefits						Pension benefits						Other benefits
(in thousands)	2011			2010			2011			2010			2011			2010			2011			2010

Service cost	$	8,474		$	6,772		$	1,129		$	1,131		$	17,039		$	13,382		$	2,352		$	2,219
Interest cost	14,803			14,658			2,340			2,571			29,652			29,237			4,724			5,167
Expected return on plan assets	(15,352		)	(15,353		)	(2,618		)	(2,728		)	(30,636		)	(30,677		)	(5,226		)	(5,443		)
Amortization of unrecognized transition obligation	—			—			(2		)	(2		)	—			—			(4		)	(4		)
Amortization of prior service gain	(187		)	(187		)	(312		)	(56		)	(374		)	(374		)	(539		)	(111		)
Recognized actuarial loss	4,016			1,767			37			1			8,136			3,452			55			4
Net periodic benefit cost	11,754			7,657			574			917			23,817			15,020			1,362			1,832
Impact of PUC D&Os	(556		)	2,020			1,734			1,333			(2,100		)	5,028			2,752			2,621
Net periodic benefit cost (adjusted for impact of PUC D&Os)	$	11,198		$	9,677		$	2,308		$	2,250		$	21,717		$	20,048		$	4,114		$	4,453

HECO and its subsidiaries recorded retirement benefits expense of $19 million for each of the first six months of 2011 and 2010. The electric utilities charged a portion of the net periodic benefit cost to plant.

Defined contribution plan. For the first six months of 2011, the utilities’ expense for matching contributions under the HEIRSP was immaterial.

5 · Commitments and contingencies

Hawaii Clean Energy Initiative. In January 2008, the State of Hawaii (State) and the U.S. Department of Energy signed a memorandum of understanding establishing the Hawaii Clean Energy Initiative (HCEI). In October 2008, the Governor of the State, the State Department of Business, Economic Development and Tourism, the Division of Consumer Advocacy of the State Department of Commerce and Consumer Affairs, and HECO, on behalf of itself and its subsidiaries, HELCO and MECO (collectively, the parties), signed an agreement setting forth goals and objectives under the HCEI and the related commitments of the parties (the Energy Agreement), including pursuing a wide range of actions to decrease the State’s dependence on imported fossil fuels through substantial increases in renewable energy and programs intended to secure greater energy efficiency and conservation. Many of the actions and programs included in the Energy Agreement require approval of the PUC.

Renewable energy projects. HECO and its subsidiaries continue to negotiate with developers of proposed projects to integrate power into its grid from a variety of renewable energy sources, including solar, biomass, wind, ocean thermal energy conversion, wave and others. This includes HECO’s commitment to integrate wind power into the Oahu electrical grid that would be imported via a yet-to-be-built undersea transmission cable system from a windfarm proposed to be built on the island of Lanai. The State and HECO are working together to ensure the supporting infrastructure needed is in place to reliably accommodate this large increment of wind power, including appropriate additional storage capacity investments and any required utility system connections or interfaces with the cable and the windfarm facility. In December 2009, the PUC allowed HECO to defer the costs of studies for this large wind project for later review of prudence and reasonableness, and HECO is now seeking PUC approval to recover the deferred costs totaling $3.9 million through the REIP surcharge. Additionally, in July 2011, the PUC directed HECO to draft an RFP for 200 MW or more of renewable energy to be delivered to Oahu and to submit the draft RFP to the PUC by mid-October 2011.

Interim increases. As of June 30, 2011, HECO and its subsidiaries had recognized $11 million of revenues with respect to interim orders related to general rate increase requests. Revenue amounts recorded pursuant to interim orders are subject to refund, with interest, if they exceed amounts allowed in a final order.

Major projects. Many public utility projects require PUC approval and various permits from other governmental agencies. Difficulties in obtaining, or the inability to obtain, the necessary approvals or permits can result in

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significantly increased project costs or even cancellation of projects. Further, completion of projects is subject to various risks, such as problems or disputes with vendors. In the event a project does not proceed, or if it becomes probable the PUC will disallow cost recovery for all or part of a project, project costs may need to be written off in amounts that could result in significant reductions in HECO’s consolidated net income. Significant projects whose costs (or costs in excess of estimates) have not yet been allowed in rate base by a final PUC order include those described below.

In May 2011, based upon recommendations solicited from the Consumer Advocate, the PUC ordered that independently conducted regulatory audits on the reasonableness of costs incurred for HECO’s East Oahu Transmission Project, Campbell Industrial Park combustion turbine project, and Customer Information System Project be undertaken. Any revenue requirements arising from specific project costs being audited shall either remain interim and subject to refund until audit completion, or remain within regulatory deferral accounts. In the Interim D&O, the PUC approved the portion of the settlement agreement allowing HECO to defer the portion of costs that are in excess of prior PUC approved amounts and related depreciation for HECO’s East Oahu Transmission Project Phase 1 ($43 million) and Campbell Industrial Park combustion turbine project ($32 million) until completion of an independently conducted regulatory review on the reasonableness of the total project costs. The PUC approved the accrual of a carrying charge on the cost of such projects not yet included in rates and the related depreciation expense, from July 1, 2011 until the regulatory reviews are completed and the PUC has issued an order allowing the remaining project costs in electric rates. For accounting purposes, HECO will record the equity portion of the carrying charge when it is allowed in electric rates. However, the PUC did not approve the agreement to defer expenses (subject to a limit to which the parties agreed) associated with the yet-to-be completed Customer Information System.

Campbell Industrial Park 110 MW combustion turbine No. 1 (CIP CT-1) and transmission line. HECO’s incurred costs for this project, which was placed in service in 2009, were $195 million, including $9 million of allowance for funds used during construction (AFUDC). HECO’s current rates reflect recovery of project costs of $163 million. See “Major projects” above regarding the process for determining recovery of the remaining costs for this project. Management believes no adjustment to project costs is required as of June 30, 2011.

East Oahu Transmission Project (EOTP). HECO had planned a project to construct a partially underground transmission line to a major substation. However, in 2002, an application for a permit, which would have allowed construction in a route through conservation district lands, was denied. In 2007, the PUC approved HECO’s request to expend funds for a revised EOTP using different routes requiring the construction of subtransmission lines in two phases (then estimated at $56 million - $42 million for Phase 1 and $14 million for Phase 2), but did not address the issue as to whether the pre-2003 planning and permitting costs, and related AFUDC, should be included in the project costs. That issue was to be addressed in a subsequent proceeding and will now be reviewed in the independently conducted regulatory audits.

Phase 1 was placed in service on June 29, 2010. As of June 30, 2011, HECO’s incurred costs for Phase 1 of this project was $59 million (as a result of higher costs and the project delays), including (i) $12 million of pre-2003 planning and permitting costs, (ii) $24 million of planning, permitting and construction costs incurred after the denial of the permit and (iii) $23 million for AFUDC. The interim D&O issued in HECO’s 2011 test year rate case reflects approximately $16 million of EOTP Phase 1 costs and related depreciation expense in determining revenue requirements. See “Major projects” above regarding the process for determining recovery of the remaining costs for EOTP Phase 1.

In April 2010, HECO proposed a modification of Phase 2 that uses smart grid technology and is estimated to cost $10 million (total cost of $15 million less $5 million of funding through the Smart Grid Investment Grant Program of the American Recovery and Reinvestment Act of 2009). In October 2010, the PUC approved HECO’s modification request for Phase 2, which is projected for completion in 2012. As of June 30, 2011, HECO’s incurred costs for Phase 2 of this project amounted to $5 million.

Management believes no adjustment to project costs is required as of June 30, 2011.

Customer Information System Project. In 2005, the PUC approved the utilities’ request to (i) expend the then-estimated $20 million for a new Customer Information System (CIS), provided that no part of the project costs may

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be included in rate base until the project is in service and is “used and useful for public utility purposes,” and (ii) defer certain computer software development costs, accumulate AFUDC during the deferral period, amortize the deferred costs over a specified period and include the unamortized deferred costs in rate base, subject to specified conditions.

HECO signed a contract with a software company in March 2006 with a transition to the new CIS originally scheduled to occur in February 2008, which transition did not occur. Disputes over the parties’ contractual obligations resulted in litigation, which subsequently was settled. HECO subsequently contracted with a new CIS software vendor and a new system integrator. The CIS project is proceeding with the implementation of the new software system. As of June 30, 2011, HECO’s total deferred and capital cost estimate for the CIS was $57 million (of which $30 million was recorded). Management believes no adjustment to project costs is required as of June 30, 2011.

Environmental regulation. HECO and its subsidiaries are subject to environmental laws and regulations that regulate the operation of existing facilities, the construction and operation of new facilities and the proper cleanup and disposal of hazardous waste and toxic substances. In recent years, legislative and regulatory activity related to the environment, including proposals and rulemaking under the Clean Air Act (CAA) and Clean Water Act (CWA), has increased significantly and management anticipates that such activity will continue.

On April 20, 2011, the Federal Register published the federal Environmental Protection Agency’s (EPA’s) proposed regulations required by section 316(b) of the CWA designed to protect aquatic organisms from adverse impacts associated with existing power plant cooling water intake structures. The proposed regulations would apply to the cooling water systems for the steam generating units at the utilities’ Honolulu, Kahe and Waiau power plants on the island of Oahu. Although the proposed regulations provide some flexibility, management believes they do not adequately focus on site-specific conditions and cost-benefit factors and, if adopted as proposed, would require significant capital and annual O&M expenditures. As proposed, the regulations would require facilities to come into compliance within 8 years of the effective date of the final rule, which the EPA expects to issue in 2012.

Subsequently, on May 3, 2011, the Federal Register published the EPA’s proposed National Emission Standards for Hazardous Air Pollutants for fossil-fuel fired steam electrical generating units (EGUs) that would establish Maximum Achievable Control Technology (MACT) standards for the control of hazardous air pollutants (HAP) in emissions from new and existing EGUs. The proposed rules, also known as EGU MACT, would apply to the 14 EGUs at the utilities’ Honolulu, Kahe and Waiau power plants. As proposed, the regulations would require significant capital and annual expenditures for the installation and operation of emission control equipment on the utilities’ EGUs. The CAA requires that facilities come into compliance with final MACT standards within 3 years of the final rule, although facilities may be granted a 1 year extension to install emission control technology. In view of the isolated nature of HECO’s electrical system and the proposed requirement to install control equipment on all HECO steam generating units while maintaining system reliability, the EGU MACT compliance schedule poses a significant challenge to HECO. Under the terms of a settlement agreement, the EPA is required to issue the final rule by November 16, 2011.

Depending upon the final outcome of the CWA 316(b) regulations, possible changes in CWA effluent standards, the EGU MACT regulations, the tightening of the National Ambient Air Quality Standards, and the Regional Haze rule under the CAA, HECO and its subsidiaries may be required to incur material capital expenditures and other compliance costs. Additionally, the combined effects of these regulatory initiatives may result in a decision to retire certain generating units earlier than anticipated.

HECO, HELCO and MECO, like other utilities, periodically experience petroleum or other chemical releases into the environment associated with current operations and report and take action on these releases when and as required by applicable law and regulations. Except as otherwise disclosed herein, HECO and its subsidiaries believe the costs of responding to their releases identified to date will not have a material adverse effect, individually or in the aggregate, on HECO’s consolidated results of operations, financial condition or liquidity.

Global climate change and greenhouse gas (GHG) emissions reduction. National and international concern about climate change and the contribution of GHG emissions (including carbon dioxide emissions from the

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combustion of fossil fuels) to global warming have led to action by the State and to federal legislative and regulatory proposals to reduce GHG emissions.

In July 2007, Act 234, which requires a statewide reduction of GHG emissions by January 1, 2020 to levels at or below the statewide GHG emission levels in 1990, became law in Hawaii. The electric utilities are participating in a Task Force established under Act 234, which is charged with developing a work plan and regulatory approach to reduce GHG emissions, as well as in initiatives aimed at reducing their GHG emissions, such as those being implemented under the Energy Agreement. Because the regulations implementing Act 234 have not yet been promulgated, management cannot predict the impact of Act 234 on the electric utilities, but compliance costs could be significant.

Several approaches (e.g., “cap and trade”) to GHG emission reduction have been either introduced or discussed in the U.S. Congress; however, no federal legislation has yet been enacted.

On September 22, 2009, the EPA issued its Final Mandatory Reporting of Greenhouse Gases Rule, which requires that sources emitting GHGs above certain threshold levels monitor and report GHG emissions. The utilities’ reports for 2010 are due on September 30, 2011. In December 2009, the EPA made the finding that motor vehicle GHG emissions endanger public health or welfare. Management believes the EPA will make the same or similar endangerment finding regarding GHG emissions from stationary sources like the utilities’ generating units.

In June 2010, the EPA issued its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule” (GHG Tailoring Rule) that created new thresholds for GHG emissions from new and existing facilities. States may need to increase fees to cover the increased level of activity caused by this rule. Effective January 2, 2011, under the Prevention of Significant Deterioration program, permitting of new or modified stationary sources (such as utility electrical generating units) that have the potential to emit GHGs in greater quantities than the thresholds in the GHG Tailoring Rule will entail GHG emissions evaluation, analysis and, potentially, control requirements. In January 2011, the EPA announced that it plans to defer, for three years, GHG permitting requirements for carbon dioxide (CO2) emissions from biomass-fired and other biogenic sources. The utilities are evaluating the impact of this deferral on their generation units that are or will be fired on biofuels.

HECO and its subsidiaries have taken, and continue to identify opportunities to take, direct action to reduce GHG emissions from their operations, including, but not limited to, supporting DSM programs that foster energy efficiency, using renewable resources for energy production and purchasing power from IPPs generated by renewable resources, burning renewable biodiesel in HECO’s CIP CT-1, using biodiesel for startup and shutdown of selected MECO generation units, and testing biofuel blends in other HECO and MECO generating units. Management is unable to evaluate the ultimate impact on the utilities’ operations of eventual comprehensive GHG regulation. However, management believes that the various initiatives it is undertaking will provide a sound basis for managing the electric utilities’ carbon footprint and meeting GHG reduction goals that will ultimately emerge.

While the timing, extent and ultimate effects of climate change cannot be determined with any certainty, climate change is predicted to result in sea level rise, which could potentially impact coastal and other low-lying areas (where much of the utilities’ electric infrastructure is sited), and could cause erosion of beaches, saltwater intrusion into aquifers and surface ecosystems, higher water tables and increased flooding and storm damage due to heavy rainfall. The effects of climate change on the weather (for example, floods or hurricanes), sea levels, and water availability and quality have the potential to materially adversely affect the results of operations, financial condition and liquidity of the electric utilities. For example, severe weather could cause significant harm to the electric utilities’ physical facilities.

The utilities are undertaking an adaptation survey of their facilities as a step in developing a longer-term strategy for responding to the consequences of global climate change.

Fuel contracts and power purchase agreements. HECO and Chevron Products Company, a division of Chevron USA, Inc. (Chevron), are parties to an amended contract for the purchase/sale of low sulfur fuel oil (LSFO), which terminates on April 30, 2013.

HECO and Tesoro Hawaii Corporation (Tesoro) are parties to an amended LSFO supply contract (LSFO contract). The term of the amended agreement runs through April 30, 2013 and may automatically renew for annual terms thereafter unless earlier terminated by either party.

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The energy charge for energy purchased from Kalaeloa under HECO’s PPA with Kalaeloa is based, in part, on the price Kalaeloa pays Tesoro for fuel oil under a Facility Fuel Supply Contract (fuel contract) between them. Kalaeloa and Tesoro have negotiated a proposed amendment to the pricing formula in their fuel contract. The amendment could result in higher fuel prices for Kalaeloa, which would in turn increase the energy charge paid by HECO to Kalaeloa. HECO consented to the amendment on September 7, 2010.

On May 13, 2011, the PUC approved the latest Chevron and Tesoro amendments and HECO’s consent to the Kalaeloa-Tesoro amendment and allowed HECO to include the costs incurred under the amendments in its ECAC, to the extent such costs are not recovered through HECO’s base rates.

Asset retirement obligations. Asset retirement obligations (AROs) represent legal obligations associated with the retirement of certain tangible long-lived assets, are measured as the present value of the projected costs for the future retirement of specific assets and are recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made. HECO and its subsidiaries’ recognition of AROs have no impact on its earnings. The cost of the AROs is recovered over the life of the asset through depreciation. AROs recognized by HECO and its subsidiaries relate to obligations to retire plant and equipment, including removal of asbestos and other hazardous materials. In September 2009, HECO recorded an estimated ARO of $23 million related to removing retired generating units at its Honolulu power plant, including abating asbestos and lead-based paint. The obligation was subsequently increased in June 2010, due to an increase in the estimated costs of the removal project. In August 2010, HECO recorded a similar estimated ARO of $12 million related to removing retired generating units at HECO’s Waiau power plant.

Changes to the ARO liability included in “Other liabilities” on HECO’s balance sheet were as follows:

(in thousands)	2011			2010
Balance, January 1	$	48,630		$	23,746
Accretion expense	1,134			1,143
Liabilities incurred	—			—
Liabilities settled	(573		)	(11		)
Revisions in estimated cash flows	—			11,141
Balance, June 30	$	49,191		$	36,019

Collective bargaining agreements. As of June 30, 2011, approximately 53% of the electric utilities’ employees were members of the International Brotherhood of Electrical Workers, AFL-CIO, Local 1260, which is the only union representing employees of the electric utilities. On March 11, 2011, the union’s members ratified a new collective bargaining agreement and a new benefit agreement. The new collective bargaining agreement covers a term from January 1, 2011 to October 31, 2013 and provides for non-compounded wage increases (1.75%, 2.5%, and 3.0% for 2011, 2012 and 2013, respectively). The new benefit agreement covers a term from January 1, 2011 to October 31, 2014 and includes changes to medical, dental and vision plans with increased employee contributions and changes to retirement benefits for employees. See Note 4.

Limited insurance. HECO and its subsidiaries purchase insurance to protect themselves against loss or damage to their properties and against claims made by third-parties and employees. However, the protection provided by such insurance is limited in significant respects and, in some instances, there is no coverage. HECO, HELCO and MECO’s transmission and distribution systems (excluding substations) have a replacement value roughly estimated at $5 billion and are uninsured. Similarly, HECO, HELCO and MECO have no business interruption insurance. If a hurricane or other uninsured catastrophic natural disaster were to occur, and if the PUC were not to allow the utilities to recover from ratepayers restoration costs and revenues lost from business interruption, their results of operations, financial condition and liquidity could be materially adversely impacted. Also, if a series of losses occurred, each of which were subject to an insurance deductible amount, or if the maximum limit of the available insurance were substantially exceeded, the utilities could incur losses in amounts that would have a material adverse effect on their results of operations, financial condition and liquidity.

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6 · Cash flows

Supplemental disclosures of cash flow information. For the six months ended June 30, 2011 and 2010, HECO and its subsidiaries paid interest amounting to $29 million and $28 million, respectively.

For the six months ended June 30, 2011 and 2010, HECO and its subsidiaries paid/(received) income taxes amounting to $(27) million and $37 million, respectively. Income taxes were received in 2011 primarily due to the refunding of estimated tax payments made prior to the extension of bonus depreciation provisions.

Supplemental disclosure of noncash activities. The allowance for equity funds used during construction, which was charged to construction in progress as part of the cost of electric utility plant, amounted to $2.6 million and $3.6 million for the six months ended June 30, 2011 and 2010, respectively.

Noncash capital expenditures were $10 million and $7 million for the six months ended June 30, 2011 and 2010, respectively.

7 · Recent accounting pronouncements and interpretations

For a discussion of recent accounting pronouncements and interpretations, see Note 12 of HEI’s “Notes to Consolidated Financial Statements.

8 · Fair value measurements

Fair value estimates are based on the price that would be received to sell an asset, or paid upon the transfer of a liability, in an orderly transaction between market participants at the measurement date. The fair value estimates are generally determined based on assumptions that market participants would use in pricing the asset or liability and are based on market data obtained from independent sources. However, in certain cases, the electric utilities use their own assumptions about market participant assumptions based on the best information available in the circumstances. These valuations are estimates at a specific point in time, based on relevant market information, information about the financial instrument and judgments regarding future expected loss experience, economic conditions, risk characteristics of various financial instruments and other factors. These estimates do not reflect any premium or discount that could result if the electric utilities were to sell their entire holdings of a particular financial instrument at one time. Because no market exists for a portion of the electric utilities’ financial instruments, fair value estimates cannot be determined with precision. Changes in the underlying assumptions used, including discount rates and estimates of future cash flows, could significantly affect the estimates. Fair value estimates are provided for certain financial instruments without attempting to estimate the value of anticipated future business and the value of assets and liabilities that are not considered financial instruments. In addition, the tax ramifications related to the realization of the unrealized gains and losses could have a significant effect on fair value estimates, but have not been considered in determining such fair values.

The electric utilities used the following methods and assumptions to estimate the fair value of each applicable class of financial instruments for which it is practicable to estimate that value:

Cash and cash equivalents and short-term borrowings. The carrying amount approximated fair value because of the short maturity of these instruments.

Off-balance sheet financial instruments. Fair value of HECO-obligated preferred securities of trust subsidiaries was based on quoted market prices.

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The estimated fair values of the financial instruments held or issued by the electric utilities were as follows:

	June 30, 2011				December 31, 2010
(in thousands)	Carrying amount		Estimated fair value		Carrying amount		Estimated fair value

Financial assets
Cash and cash equivalents, excluding money market accounts	$	844	$	844	$	122,936	$	122,936
Money market accounts—fair value measurements on a recurring basis using significant other observable inputs (Level 2)	24,690		24,690		—		—

Financial liabilities
Long-term debt, net, including amounts due within one year	1,058,006		1,004,669		1,057,942		1,020,550

Off-balance sheet item
HECO-obligated preferred securities of trust subsidiary	50,000		50,040		50,000		52,500

Fair value measurements on a nonrecurring basis. From time to time, the utilities may be required to measure certain assets at fair value on a nonrecurring basis in accordance with GAAP. These adjustments to fair value usually result from the application of lower-of-cost-or-market accounting or write-downs of individual assets. As of June 30, 2011, there were no adjustments to fair value for assets measured at fair value on a nonrecurring basis in accordance with GAAP.

From time to time, the utilities may be required to measure certain liabilities at fair value on a nonrecurring basis in accordance with GAAP. The fair value of the utilities ARO (Level 3) was determined by discounting the expected future cash flows using market-observable risk-free rates as adjusted by HECO’s credit spread. See Note 5.

9 · Credit agreement

HECO maintains a revolving noncollateralized credit agreement establishing a line of credit facility of $175 million, with a letter of credit sub-facility, with a syndicate of eight financial institutions, expiring on May 7, 2013. The credit facility will be maintained to support the issuance of commercial paper, but also may be drawn to repay HECO’s short-term indebtedness, to make loans to subsidiaries and for HECO’s capital expenditures, working capital and general corporate purposes.

10 · Reconciliation of electric utility operating income per HEI and HECO consolidated statements of income

	Three months ended June 30						Six months ended June 30
(in thousands)	2011			2010			2011			2010
Operating income from regulated and nonregulated activities before income taxes (per HEI consolidated statements of income)	$	42,518		$	41,435		$	87,726		$	84,044
Deduct:
Income taxes on regulated activities	(11,160		)	(11,113		)	(22,770		)	(22,154		)
Revenues from nonregulated activities	(1,086		)	(2,001		)	(2,120		)	(3,400		)
Add: Expenses from nonregulated activities	268			2,529			423			2,767
Operating income from regulated activities after income taxes (per HECO consolidated statements of income)	$	30,540		$	30,850		$	63,259		$	61,257

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11 · Subsequent event

12 · Consolidating financial information

HECO is not required to provide separate financial statements or other disclosures concerning HELCO and MECO to holders of the 2004 Debentures issued by HELCO and MECO to Trust III since all of their voting capital stock is owned, and their obligations with respect to these securities have been fully and unconditionally guaranteed, on a subordinated basis, by HECO. Consolidating information is provided below for these and other HECO subsidiaries for the periods ended and as of the dates indicated.

HECO also unconditionally guarantees HELCO’s and MECO’s obligations (a) to the State of Hawaii for the repayment of principal and interest on Special Purpose Revenue Bonds issued for the benefit of HELCO and MECO and (b) relating to the trust preferred securities of Trust III (see Note 2 above). HECO is also obligated, after the satisfaction of its obligations on its own preferred stock, to make dividend, redemption and liquidation payments on HELCO’s and MECO’s preferred stock if the respective subsidiary is unable to make such payments.

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI	UBC		Reclassifications and eliminations		HECO Consolidated

Operating revenues	$	510,653		110,595		106,404		—	—		—		$	727,652
Operating expenses
Fuel oil	220,231			32,123		59,787		—	—		—		312,141
Purchased power	131,921			32,242		7,574		—	—		—		171,737
Other operation	48,396			9,524		9,468		—	—		—		67,388
Maintenance	22,077			4,297		4,902		—	—		—		31,276
Depreciation	22,885			8,148		5,225		—	—		—		36,258
Taxes, other than income taxes	47,108			10,163		9,881		—	—		—		67,152
Income taxes	3,640			4,725		2,795		—	—		—		11,160
	496,258			101,222		99,632		—	—		—		697,112
Operating income	14,395			9,373		6,772		—	—		—		30,540
Other income
Allowance for equity funds used during construction	974			233		110		—	—		—		1,317
Equity in earnings of subsidiaries	10,963			—		—		—	—		(10,963	)	—
Other, net	626			214		62		—	(1	)	(3	)	898
	12,563			447		172		—	(1	)	(10,966	)	2,215
Interest and other charges
Interest on long-term debt	9,131			2,984		2,268		—	—		—		14,383
Amortization of net bond premium and expense	503			137		126		—	—		—		766
Other interest charges	442			93		104		—	—		(3	)	636
Allowance for borrowed funds used during construction	(412		)	(102	)	(39	)	—	—		—		(553		)
	9,664			3,112		2,459		—	—		(3	)	15,232
Net income (loss)	17,294			6,708		4,485		—	(1	)	(10,963	)	17,523
Preferred stock dividend of subsidiaries	—			133		96		—	—		—		229
Net income (loss) attributable to HECO	17,294			6,575		4,389		—	(1	)	(10,963	)	17,294
Preferred stock dividends of HECO	270			—		—		—	—		—		270
Net income (loss) for common stock	$	17,024		6,575		4,389		—	(1	)	(10,963	)	$	17,024

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Three months ended June 30, 2010

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated

Operating revenues	$	407,566		91,443		83,085		—		—		—		$	582,094
Operating expenses
Fuel oil	150,121			23,153		42,048		—		—		—		215,322
Purchased power	104,693			27,763		7,057		—		—		—		139,513
Other operation	44,220			8,232		7,802		—		—		—		60,254
Maintenance	18,566			7,915		5,742		—		—		—		32,223
Depreciation	21,912			9,127		7,610		—		—		—		38,649
Taxes, other than income taxes	37,834			8,509		7,827		—		—		—		54,170
Income taxes	8,847			1,395		871		—		—		—		11,113
	386,193			86,094		78,957		—		—		—		551,244
Operating income	21,373			5,349		4,128		—		—		—		30,850
Other income
Allowance for equity funds used during construction	1,599			106		142		—		—		—		1,847
Equity in earnings of subsidiaries	3,426			—		—		—		—		(3,426	)	—
Other, net	890			140		(629	)	(2	)	(5	)	(22	)	372
	5,915			246		(487	)	(2	)	(5	)	(3,448	)	2,219
Interest and other charges
Interest on long-term debt	9,131			2,984		2,268		—		—		—		14,383
Amortization of net bond premium and expense	484			118		124		—		—		—		726
Other interest charges	441			95		95		—		—		(22	)	609
Allowance for borrowed funds used during construction	(680		)	(53	)	(57	)	—		—		—		(790		)
	9,376			3,144		2,430		—		—		(22	)	14,928
Net income (loss)	17,912			2,451		1,211		(2	)	(5	)	(3,426	)	18,141
Preferred stock dividend of subsidiaries	—			133		96		—		—		—		229
Net income (loss) attributable to HECO	17,912			2,318		1,115		(2	)	(5	)	(3,426	)	17,912
Preferred stock dividends of HECO	270			—		—		—		—		—		270
Net income (loss) for common stock	$	17,642		2,318		1,115		(2	)	(5	)	(3,426	)	$	17,642

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Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Six months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated

Operating revenues	$	960,477		210,230		201,246		—		—		—		$	1,371,953
Operating expenses
Fuel oil	403,497			58,614		110,890		—		—		—		573,001
Purchased power	244,672			62,264		12,759		—		—		—		319,695
Other operation	95,651			17,792		19,476		—		—		—		132,919
Maintenance	43,269			8,148		9,055		—		—		—		60,472
Depreciation	45,768			16,471		10,451		—		—		—		72,690
Taxes, other than income taxes	88,997			19,336		18,814		—		—		—		127,147
Income taxes	8,338			8,494		5,938		—		—		—		22,770
	930,192			191,119		187,383		—		—		—		1,308,694
Operating income	30,285			19,111		13,863		—		—		—		63,259
Other income
Allowance for equity funds used during construction	1,934			316		311		—		—		—		2,561
Equity in earnings of subsidiaries	22,453			—		—		—		—		(22,453	)	—
Other, net	1,358			320		154		(2	)	(4	)	(18	)	1,808
	25,745			636		465		(2	)	(4	)	(22,471	)	4,369
Interest and other charges
Interest on long-term debt	18,261			5,969		4,536		—		—		—		28,766
Amortization of net bond premium and expense	1,016			280		253		—		—		—		1,549
Other interest charges	820			174		199		—		—		(18	)	1,175
Allowance for borrowed funds used during construction	(820		)	(135	)	(118	)	—		—		—		(1,073		)
	19,277			6,288		4,870		—		—		(18	)	30,417
Net income (loss)	36,753			13,459		9,458		(2	)	(4	)	(22,453	)	37,211
Preferred stock dividend of subsidiaries	—			267		191		—		—		—		458
Net income (loss) attributable to HECO	36,753			13,192		9,267		(2	)	(4	)	(22,453	)	36,753
Preferred stock dividends of HECO	540			—		—		—		—		—		540
Net income (loss) for common stock	$	36,213		13,192		9,267		(2	)	(4	)	(22,453	)	$	36,213

Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Income (Loss) (unaudited)

Six months ended June 30, 2010

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated

Operating revenues	$	783,670		180,475		164,661		—		—		—		$	1,128,806
Operating expenses
Fuel oil	296,463			46,632		83,979		—		—		—		427,074
Purchased power	190,554			53,465		12,276		—		—		—		256,295
Other operation	85,846			17,249		16,403		—		—		—		119,498
Maintenance	35,640			11,310		12,326		—		—		—		59,276
Depreciation	43,825			18,253		15,213		—		—		—		77,291
Taxes, other than income taxes	73,557			16,837		15,567		—		—		—		105,961
Income taxes	16,752			4,042		1,360		—		—		—		22,154
	742,637			167,788		157,124		—		—		—		1,067,549
Operating income	41,033			12,687		7,537		—		—		—		61,257
Other income
Allowance for equity funds used during construction	3,158			201		261		—		—		—		3,620
Equity in earnings of subsidiaries	8,719			—		—		—		—		(8,719	)	—
Other, net	2,004			255		(584	)	(4	)	(10	)	(48	)	1,613
	13,881			456		(323	)	(4	)	(10	)	(8,767	)	5,233
Interest and other charges
Interest on long-term debt	18,261			5,969		4,536		—		—		—		28,766
Amortization of net bond premium and expense	917			235		241		—		—		—		1,393
Other interest charges	866			196		194		—		—		(48	)	1,208
Allowance for borrowed funds used during construction	(1,364		)	(102	)	(103	)	—		—		—		(1,569		)
	18,680			6,298		4,868		—		—		(48	)	29,798
Net income (loss)	36,234			6,845		2,346		(4	)	(10	)	(8,719	)	36,692
Preferred stock dividend of subsidiaries	—			267		191		—		—		—		458
Net income (loss) attributable to HECO	36,234			6,578		2,155		(4	)	(10	)	(8,719	)	36,234
Preferred stock dividends of HECO	540			—		—		—		—		—		540
Net income (loss) for common stock	$	35,694		6,578		2,155		(4	)	(10	)	(8,719	)	$	35,694

Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,241		5,182		3,016		—	—	—		$	51,439
Plant and equipment	3,028,815			1,023,920		889,152		—	—	—		4,941,887
Less accumulated depreciation	(1,158,380		)	(406,262	)	(403,565	)	—	—	—		(1,968,207		)
Construction in progress	94,880			14,545		13,521		—	—	—		122,946
Net utility plant	2,008,556			637,385		502,124		—	—	—		3,148,065
Investment in wholly owned subsidiaries, at equity	509,216			—		—		—	—	(509,216	)	—
Current assets
Cash and cash equivalents	23,287			1,844		291		85	27	—		25,534
Advances to affiliates	—			36,800		17,000		—	—	(53,800	)	—
Customer accounts receivable, net	119,404			28,788		26,242		—	—	—		174,434
Accrued unbilled revenues, net	88,283			17,787		16,793		—	—	—		122,863
Other accounts receivable, net	11,485			1,126		1,125		—	—	(7,311	)	6,425
Fuel oil stock, at average cost	109,190			20,919		29,105		—	—	—		159,214
Materials and supplies, at average cost	19,846			4,586		13,775		—	—	—		38,207
Prepayments and other	31,631			4,393		5,108		—	—	(38	)	41,094
Regulatory assets	7,407			1,309		1,266		—	—	—		9,982
Total current assets	410,533			117,552		110,705		85	27	(61,149	)	577,753
Other long-term assets
Regulatory assets	348,662			59,947		60,175		—	—	—		468,784
Unamortized debt expense	8,648			2,515		1,982		—	—	—		13,145
Other	46,435			9,261		15,679		—	—	—		71,375
Total other long-term assets	403,745			71,723		77,836		—	—	—		553,304
Total assets	$	3,332,050		826,660		690,665		85	27	(570,365	)	$	4,279,122
Capitalization and liabilities
Capitalization
Common stock equity	$	1,338,406		275,705		233,401		84	26	(509,216	)	$	1,338,406
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—	—		34,293
Long-term debt, net	629,722			204,095		166,689		—	—	—		1,000,506
Total capitalization	1,990,421			486,800		405,090		84	26	(509,216	)	2,373,205
Current liabilities
Current portion of long-term debt	42,580			7,200		7,720		—	—	—		57,500
Short-term borrowings-affiliate	53,800			—		—		—	—	(53,800	)	—
Accounts payable	98,986			23,218		17,976		—	—	—		140,180
Interest and preferred dividends payable	13,383			4,319		2,756		—	—	(1	)	20,457
Taxes accrued	114,485			29,794		29,570		—	—	(38	)	173,811
Other	37,748			12,770		14,610		1	1	(7,310	)	57,820
Total current liabilities	360,982			77,301		72,632		1	1	(61,149	)	449,768
Deferred credits and other liabilities
Deferred income taxes	217,426			51,034		33,043		—	—	—		301,503
Regulatory liabilities	211,981			59,291		38,537		—	—	—		309,809
Unamortized tax credits	34,661			13,153		12,329		—	—	—		60,143
Retirement benefits liability	256,391			37,360		42,123		—	—	—		335,874
Other	68,403			28,368		12,560		—	—	—		109,331
Total deferred credits and other liabilities	788,862			189,206		138,592		—	—	—		1,116,660
Contributions in aid of construction	191,785			73,353		74,351		—	—	—		339,489
Total capitalization and liabilities	$	3,332,050		826,660		690,665		85	27	(570,365	)	$	4,279,122

Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Balance Sheet (unaudited)

December 31, 2010

(in thousands)	HECO			HELCO		MECO		RHI	UBC	Reclassifications and Eliminations		HECO Consolidated
Assets
Utility plant, at cost
Land	$	43,240		5,108		3,016		—	—	—		$	51,364
Plant and equipment	2,984,887			1,030,520		881,567		—	—	—		4,896,974
Less accumulated depreciation	(1,134,423		)	(408,704	)	(397,932	)	—	—	—		(1,941,059		)
Construction in progress	78,934			9,828		12,800		—	—	—		101,562
Net utility plant	1,972,638			636,752		499,451		—	—	—		3,108,841
Investment in wholly owned subsidiaries, at equity	500,801			—		—		—	—	(500,801	)	—
Current assets
Cash and cash equivalents	121,019			1,229		594		89	5	—		122,936
Advances to affiliates	—			30,950		29,500		—	—	(60,450	)	—
Customer accounts receivable, net	93,474			23,484		21,213		—	—	—		138,171
Accrued unbilled revenues, net	71,712			16,018		16,654		—	—	—		104,384
Other accounts receivable, net	11,536			3,319		668		—	—	(6,147	)	9,376
Fuel oil stock, at average cost	121,280			15,751		15,674		—	—	—		152,705
Materials and supplies, at average cost	18,890			4,498		13,329		—	—	—		36,717
Prepayments and other	36,974			9,825		8,417		—	—	—		55,216
Regulatory assets	5,294			1,064		991		—	—	—		7,349
Total current assets	480,179			106,138		107,040		89	5	(66,597	)	626,854
Other long-term assets
Regulatory assets	352,038			61,051		57,892		—	—	—		470,981
Unamortized debt expense	9,240			2,681		2,109		—	—	—		14,030
Other	41,236			8,257		15,481		—	—	—		64,974
Total other long-term assets	402,514			71,989		75,482		—	—	—		549,985
Total assets	$	3,356,132		814,879		681,973		89	5	(567,398	)	$	4,285,680
Capitalization and liabilities
Capitalization
Common stock equity	$	1,337,398		270,573		230,137		86	5	(500,801	)	$	1,337,398
Cumulative preferred stock—not subject to mandatory redemption	22,293			7,000		5,000		—	—	—		34,293
Long-term debt, net	672,268			211,279		174,395		—	—	—		1,057,942
Total capitalization	2,031,959			488,852		409,532		86	5	(500,801	)	2,429,633
Current liabilities
Short-term borrowings-affiliate	60,450			—		—		—	—	(60,450	)	—
Accounts payable	135,739			22,888		20,332		—	—	—		178,959
Interest and preferred dividends payable	13,648			4,196		2,762		—	—	(3	)	20,603
Taxes accrued	116,840			31,229		27,891		—	—	—		175,960
Other	35,784			13,065		13,646		3	—	(6,144	)	56,354
Total current liabilities	362,461			71,378		64,631		3	—	(66,597	)	431,876
Deferred credits and other liabilities
Deferred income taxes	198,753			44,971		25,562		—	—	—		269,286
Regulatory liabilities	201,587			56,190		39,020		—	—	—		296,797
Unamortized tax credits	33,661			12,857		12,292		—	—	—		58,810
Retirement benefits liability	271,499			39,811		44,534		—	—	—		355,844
Other	66,898			28,739		12,433		—	—	—		108,070
Total deferred credits and other liabilities	772,398			182,568		133,841		—	—	—		1,088,807
Contributions in aid of construction	189,314			72,081		73,969		—	—	—		335,364
Total capitalization and liabilities	$	3,356,132		814,879		681,973		89	5	(567,398	)	$	4,285,680

Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Balance, December 31, 2010	$	1,337,398		270,573		230,137		86		5		(500,801	)	$	1,337,398
Comprehensive income (loss):
Net income (loss) for common stock	36,213			13,192		9,267		(2	)	(4	)	(22,453	)	36,213
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits	4,426			696		567		—		—		(1,263	)	4,426
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(4,352		)	(695	)	(568	)	—		—		1,263		(4,352		)
Comprehensive income (loss)	36,287			13,193		9,266		(2	)	(4	)	(22,453	)	36,287
Common stock dividends	(35,279		)	(8,061	)	(6,002	)	—		—		14,063		(35,279		)
Common stock issuance	—			—		—		—		25		(25	)	—
Balance, June 30, 2011	$	1,338,406		275,705		233,401		84		26		(509,216	)	$	1,338,406

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Changes in Common Stock Equity (unaudited)

Six months ended June 30, 2010

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Reclassifications and eliminations		HECO Consolidated
Balance, December 31, 2009	$	1,306,408		240,576		221,319		94		17		(462,006	)	$	1,306,408
Comprehensive income (loss):
Net income (loss) for common stock	35,694			6,578		2,155		(4	)	(10	)	(8,719	)	35,694
Retirement benefit plans:
Less: amortization of net loss, prior service gain and transition obligation included in net periodic benefit cost, net of tax benefits	1,813			385		320		—		—		(705	)	1,813
Less: reclassification adjustment for impact of D&Os of the PUC included in regulatory assets, net of taxes	(1,697		)	(376	)	(308	)	—		—		684		(1,697		)
Comprehensive income (loss)	35,810			6,587		2,167		(4	)	(10	)	(8,740	)	35,810
Common stock dividends	(26,887		)	(6,203	)	(2,276	)	—		—		8,479		(26,887		)
Common stock issue expenses	(7		)	(3	)	—		—		—		3		(7		)
Balance, June 30, 2010	$	1,315,324		240,957		221,210		90		7		(462,264	)	$	1,315,324

Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2011

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Net income (loss)	$	36,753		13,459		9,458		(2	)	(4	)	(22,453	)	$	37,211
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings	(22,503		)	—		—		—		—		22,453		(50		)
Common stock dividends received from subsidiaries	14,113			—		—		—		—		(14,063	)	50
Depreciation of property, plant and equipment	45,768			16,471		10,451		—		—		—		72,690
Other amortization	8,602			1,283		948		—		—		—		10,833
Changes in deferred income taxes	19,474			6,234		7,748		—		—		—		33,456
Changes in tax credits, net	1,193			307		56		—		—		—		1,556
Allowance for equity funds used during construction	(1,934		)	(316	)	(311	)	—		—		—		(2,561		)
Increase in cash overdraft	—			(2,527	)	222		—		—		—		(2,305		)
Changes in assets and liabilities:
Increase in accounts receivable	(25,879		)	(3,111	)	(5,486	)	—		—		1,164		(33,312		)
Increase in accrued unbilled revenues	(16,571		)	(1,769	)	(139	)	—		—		—		(18,479		)
Decrease (increase) in fuel oil stock	12,090			(5,168	)	(13,431	)	—		—		—		(6,509		)
Increase in materials and supplies	(956		)	(88	)	(446	)	—		—		—		(1,490		)
Increase in regulatory assets	(9,650		)	(1,057	)	(3,791	)	—		—		—		(14,498		)
Decrease in accounts payable	(45,638		)	(35	)	(2,615	)	—		—		—		(48,288		)
Changes in prepaid and accrued income and utility revenue taxes	3,724			3,682		4,772		—		—		—		12,178
Changes in other assets and liabilities	(18,315		)	(1,136	)	(3,809	)	(2	)	1		(1,164	)	(24,425		)
Net cash provided by (used in) operating activities	271			26,229		3,627		(4	)	(3	)	(14,063	)	16,057
Cash flows from investing activities:
Capital expenditures	(60,386		)	(13,937	)	(11,072	)	—		—		—		(85,395		)
Contributions in aid of construction	4,816			2,501		836		—		—		—		8,153
Other	77			—		—		—		—		—		77
Investment in consolidated subsidiary	(25		)	—		—		—		—		25		—
Advances from (to) affiliates	—			(5,850	)	12,500		—		—		(6,650	)	—
Net cash provided by (used in) investing activities	(55,518		)	(17,286	)	2,264		—		—		(6,625	)	(77,165		)
Cash flows from financing activities:
Common stock dividends	(35,279		)	(8,061	)	(6,002	)	—		—		14,063		(35,279		)
Preferred stock dividends of HECO and subsidiaries	(540		)	(267	)	(191	)	—		—		—		(998		)
Net decrease in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	(6,650		)	—		—		—		—		6,650		—
Proceeds from issuance of common stock	—			—		—		—		25		(25	)	—
Other	(16		)	—		(1	)	—		—		—		(17		)
Net cash provided by (used in) financing activities	(42,485		)	(8,328	)	(6,194	)	—		25		20,688		(36,294		)
Net increase (decrease) in cash and cash equivalents	(97,732		)	615		(303	)	(4	)	22		—		(97,402		)
Cash and cash equivalents, beginning of period	121,019			1,229		594		89		5		—		122,936
Cash and cash equivalents, end of period	$	23,287		1,844		291		85		27		—		$	25,534

Table of Contents

Hawaiian Electric Company, Inc. and Subsidiaries

Consolidating Statement of Cash Flows (unaudited)

Six months ended June 30, 2010

(in thousands)	HECO			HELCO		MECO		RHI		UBC		Elimination addition to (deduction from) cash flows		HECO Consolidated
Cash flows from operating activities:
Net income (loss)	$	36,234		6,845		2,346		(4	)	(10	)	(8,719	)	$	36,692
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Equity in earnings	(8,769		)	—		—		—		—		8,719		(50		)
Common stock dividends received from subsidiaries	8,529			—		—		—		—		(8,479	)	50
Depreciation of property, plant and equipment	43,825			18,253		15,213		—		—		—		77,291
Other amortization	2,411			1,716		(1,026	)	—		—		—		3,101
Changes in deferred income taxes	(3,745		)	(199	)	(578	)	—		—		—		(4,522		)
Changes in tax credits, net	1,609			238		(162	)	—		—		—		1,685
Allowance for equity funds used during construction	(3,158		)	(201	)	(261	)	—		—		—		(3,620		)
Decrease in cash overdraft	—			—		(302	)	—		—		—		(302		)
Changes in assets and liabilities:
Increase in accounts receivable	(18,653		)	(1,141	)	(2,921	)	—		—		4,457		(18,258		)
Decrease (increase) in accrued unbilled revenues	(6,884		)	316		71		—		—		—		(6,497		)
Increase in fuel oil stock	(45,841		)	(3,634	)	(284	)	—		—		—		(49,759		)
Decrease (increase) in materials and supplies	(1,102		)	(530	)	760		—		—		—		(872		)
Increase in regulatory assets	(1,331		)	(695	)	(226	)	—		—		—		(2,252		)
Increase (decrease) in accounts payable	(4,264		)	3,377		(299	)	—		—		—		(1,186		)
Changes in prepaid and accrued income and utility revenue taxes	(21,463		)	(4,904	)	(5,497	)	—		—		—		(31,864		)
Changes in other assets and liabilities	12,356			2,891		3,880		(2	)	1		(4,457	)	14,669
Net cash provided by (used in) operating activities	(10,246		)	22,332		10,714		(6	)	(9	)	(8,479	)	14,306
Cash flows from investing activities:
Capital expenditures	(51,025		)	(10,429	)	(10,043	)	—		—		—		(71,497		)
Contributions in aid of construction	5,871			2,206		1,353		—		—		—		9,430
Advances from (to) affiliates	5,250			—		2,000		—		—		(7,250	)	—
Net cash used in investing activities	(39,904		)	(8,223	)	(6,690	)	—		—		(7,250	)	(62,067		)
Cash flows from financing activities:
Common stock dividends	(26,887		)	(6,203	)	(2,276	)	—		—		8,479		(26,887		)
Preferred stock dividends of HECO and subsidiaries	(540		)	(267	)	(191	)	—		—		—		(998		)
Net increase (decrease) in short-term borrowings from nonaffiliates and affiliate with original maturities of three months or less	12,100			(5,250	)	—		—		—		7,250		14,100
Other	(948		)	(278	)	(123	)	—		—		—		(1,349		)
Net cash used in financing activities	(16,275		)	(11,998	)	(2,590	)	—		—		15,729		(15,134		)
Net increase (decrease) in cash and cash equivalents	(66,425		)	2,111		1,434		(6	)	(9	)	—		(62,895		)
Cash and cash equivalents, beginning of period	70,981			2,006		474		98		19		—		73,578
Cash and cash equivalents, end of period	$	4,556		4,117		1,908		92		10		—		$	10,683

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion updates “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in HEI’s and HECO’s Form 10-K for 2010 and should be read in conjunction with the 2010 annual consolidated financial statements of HEI and HECO and notes thereto included and incorporated by reference, respectively, in HEI’s and HECO’s Form 10-K for 2010, as well as the quarterly (as of and for the three months ended March 31, 2011 and as of and for the three and six months ended June 30, 2011) financial statements and notes thereto included in this Form 10-Q and the Form 10-Q for the first quarter of 2011.

HEI Consolidated

RESULTS OF OPERATIONS

(in thousands, except per	Three months ended June 30				%		Primary reason(s) for
share amounts)	2011		2010		change		significant change*
Revenues	$	794,319	$	655,664	21		Increase for the electric utility segment, partly offset by a decrease for the bank segment

Operating income	63,661		63,631		—		Increase for the electric utility segment and lower losses for the “other” segment, partly offset by a decrease for the bank segment

Net income for common stock	27,139		29,262		(7	)	Higher “interest expense—other than on deposit liabilities and other bank borrowings” and lower AFUDC, partly offset by lower income taxes**

Basic earnings per common share	$	0.28	$	0.31	(10	)	Lower net income and higher weighted average shares outstanding

Weighted-average number of common shares outstanding	95,393		93,159		2		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and Company employee plans

(in thousands, except per	Six months ended June 30				%		Primary reason(s) for
share amounts)	2011		2010		change		significant change*
Revenues	$	1,504,952	$	1,274,704	18		Increase for the electric utility segment, partly offset by a decrease for the bank segment

Operating income	127,036		124,338		2		Increase for the electric utility segment and lower losses for the “other” segment, partly offset by a decrease for the bank segment

Net income for common stock	55,601		56,388		(1	)	Higher “interest expense—other than on deposit liabilities and other bank borrowings” and lower AFUDC, partly offset by higher operating income and lower income taxes**

Basic earnings per common share	$	0.58	$	0.61	(5	)	Lower net income and higher weighted average shares outstanding

Weighted-average number of common shares outstanding	95,107		92,867		2		Issuances of shares under the HEI Dividend Reinvestment and Stock Purchase Plan and Company employee plans

* Also, see segment discussions which follow.

** The Company’s effective tax rates (combined federal and state) for the second quarters of 2011 and 2010 were 33% and 35%, respectively. The Company’s effective tax rates (combined federal and state) for the first six months of 2011 and 2010 were 35%.

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In 2008, the Company initiated aggressive strategies to set both the utilities and ASB on a new course — the utilities entered into an agreement with the State to create a clean energy future for Hawaii and ASB set new performance standards. In 2010 and the first six months of 2011, the Company made major progress on these strategies. The utilities advanced key HCEI initiatives, and ASB completed its performance improvement project in 2010 and demonstrated reduced risk and profitability metrics in line with or better than the average of its high performing peers in the first half of 2011 (see segment discussions below). Together, HEI’s unique combination of a utility and bank continues to provide the Company with a strong balance sheet and the financial resources to invest in the strategic growth of its subsidiaries while providing an attractive dividend for investors.

Dividends. The payout ratios for 2010 and the first half of 2011 were 102% and 106%, respectively. HEI currently expects to maintain the dividend at its present level; however, the HEI Board of Directors evaluates the dividend quarterly and considers many factors in the evaluation, including but not limited to the Company’s results of operations, the long-term prospects for the Company, and current and expected future economic conditions.

Economic conditions.

Note: The statistical data in this section is from public third-party sources (e.g., Department of Business, Economic Development and Tourism (DBEDT); University of Hawaii Economic Research Organization (UHERO); U.S. Bureau of Labor Statistics; Blue Chip Economic Indicators; U.S. Energy Information Administration; Hawaii Tourism Authority (HTA); Honolulu Board of REALTORS® Bureau of Economic Analysis and national and local newspapers).

The U.S. economy, as measured by real gross domestic product (GDP), increased at an annual rate of 1.9% in the first quarter of 2011 over the fourth quarter of 2010, according to the estimate released by the Bureau of Economic Analysis on June 24, 2011. Real GDP is estimated to slowly strengthen in the second and third quarters of 2011 by 2.0% and 3.2% compared to the preceding quarter, respectively, according to the July 2011 Blue Chip Economic Indicators. While positive growth is still expected in 2011, the consensus outlook for the U.S. economy has deteriorated since the first quarter of 2011. The decline in the real GDP growth forecast results from several factors, including continuing weak employment data, restrictions to federal, state and local government spending, and dampened personal consumption expenditures as a result of sharp increases in gasoline prices in the second quarter of 2011.

Crude oil prices reached their highest level since 2008 in April 2011. The price of a barrel of West Texas Intermediate (WTI) crude oil peaked at $113.93 on April 29, 2011 before declining to an average of $101 and $96 per barrel in May and June 2011, respectively. The U.S. Energy Information Administration’s July 2011 Short-Term Energy Outlook projected WTI to average $98 per barrel in 2011.

Meanwhile, despite significant decreases in visitor bookings from Japan following the devastating March 11, 2011 Tohoku earthquake and tsunami, state total visitor arrivals continued to see growth with a 4.7% increase year-to-date June 2011 over the same period in 2010. Visitor arrivals from Canada and the continental U.S. continued to increase year-over-year. Year-to-date June 2011 total visitor expenditures rebounded strongly with an 18.4% increase over the same period in 2010. The long term global and local effects of the tragic events in Japan remain uncertain with Japan arrivals remaining lower through the beginning of July 2011. The outlook for the visitor industry remains optimistic with China Eastern Airlines proposing the first regularly scheduled service from China (Shanghai) to start in August 2011 and the expected arrival of about 15,000 world government and business leaders from 21 economies for the Hawaii Asia Pacific Economic Cooperation summit in November 2011.

Hawaii’s seasonally adjusted unemployment rate for June 2011 of 6.0% remained well below the national unemployment rate of 9.2%. Hawaii job growth appears to be slowly spreading beyond the tourism industry with increases in areas such as professional and business services and educational services. Six of seven bargaining units of the state’s largest public union ratified a new contract ending furloughs effective July 1, 2011. The new contract calls for a 5% reduction in pay and an increased share of health care premiums. Other public unions continue to negotiate new agreements.

According to local economists, private construction has stabilized and is headed for limited growth. Government infrastructure spending bolstered construction over the past year, but this area is vulnerable in an era of increasing government frugality. The big driver in construction on Oahu is expected to be rail transit. An increase in construction jobs for the rail project is expected in late 2011, assuming no additional delays to the schedule.

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Hawaii’s housing market remained lethargic across the state, with existing home sales falling in June 2011 as compared to June 2010 when tax credits stimulated home purchases.

The Federal Open Market Committee held the federal funds rate target rate at 0 to ¼ percent on June 22, 2011, citing slower than expected economic recovery with weak labor market indicators, supply chain disruptions from the Japan tragedy, weak housing markets and low nonresidential structure investments.

Hawaii’s economic recovery is expected to strengthen despite losses in Japan arrivals as improvement spreads beyond the visitor industry. Local economists project improvement in most key indicators in 2011 and 2012.

Major tax legislation. Two bills enacted in 2010 (the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act) contained major tax provisions directly affecting the Company, including the extension of 50% bonus depreciation and 100% bonus depreciation for certain property. For the Company, the bonus depreciation provisions result in an estimated increase in federal tax depreciation of $75 million for 2010 and $165 million for 2011, primarily attributable to the utilities. A number of energy-related tax breaks were also extended, including the biodiesel credit through 2012. The Company will continue to analyze these Acts for their impacts and the opportunities they present.

Retirement benefits. For the first six months of 2011, the Company’s and HECO and its subsidiaries’ defined benefit retirement plans’ assets generated a gain, after investment management fees, of 4.9%. The market value of the defined benefit retirement plans’ assets of the Company as of June 30, 2011 was $1.0 billion (including $942 million for HECO and its subsidiaries) compared to $983 million at December 31, 2010 (including $891 million for HECO and its subsidiaries).

HEI and HECO and its subsidiaries estimate that the cash funding for their qualified defined benefit pension plans in 2011 will be about $2 million and $71 million, respectively, which should fully satisfy the minimum required contribution, including requirements of the utilities’ pension tracking mechanisms and the plans’ funding policy. See Note 4 of HECO’s “Notes to Consolidated Financial Statements.” Other factors could cause changes to the required contribution levels. The Pension Protection Act provides that if a pension plan’s funded status falls below certain levels more conservative assumptions must be used to value obligations, and restrictions on participant benefit accruals may be placed on the plans. If the plans fall below these thresholds, to avoid adverse consequences, funds in excess of the minimum required contribution may be contributed to the plan trust.

Commitments and contingencies. See Note 9 of HEI’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements and interpretations. See Note 12 of HEI’s “Notes to Consolidated Financial Statements.”

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“Other” segment.

	Three months ended June 30						Six months ended June 30						Primary reason(s) for
(in thousands)	2011			2010			2011			2010			significant change
Revenues	$	(737	)	$	(63	)	$	(752	)	$	(48	)	Higher losses on venture capital investments

Operating loss	(2,677		)	(3,579		)	(6,264		)	(7,252		)	Lower administrative and general expenses, primarily executive compensation expense

Net loss	(5,080		)	(4,511		)	(9,658		)	(9,173		)	See explanation for operating loss and higher tax benefits due to a favorable settlement with the IRS, more than offset by higher interest expense primarily due to the losses on Forward Starting Swaps

The “other” business segment includes results of the stand-alone corporate operations of HEI and American Savings Holdings, Inc. (ASHI), both holding companies; Pacific Energy Conservation Services, Inc., a contract services company which provided windfarm operational and maintenance services to an affiliated electric utility until the windfarm was dismantled (dissolved in April 2011); HEI Properties, Inc., a company holding passive, venture capital investments; and The Old Oahu Tug Service, Inc., a maritime freight transportation company that ceased operations in 1999; as well as eliminations of intercompany transactions.

FINANCIAL CONDITION

Liquidity and capital resources. The Company believes that its ability to generate cash, both internally from electric utility and banking operations and externally from issuances of equity and debt securities, commercial paper and bank borrowings, is adequate to maintain sufficient liquidity to fund its contractual obligations and commercial commitments, its forecasted capital expenditures and investments, its expected retirement benefit plan contributions and other cash requirements for the foreseeable future.

The consolidated capital structure of HEI (excluding deposit liabilities and other bank borrowings) was as follows:

(dollars in millions)	June 30, 2011				December 31, 2010

Short-term borrowings—other than bank	$	—	—	%	$	25	1	%
Long-term debt, net—other than bank	1,440		48		1,365		47
Preferred stock of subsidiaries	34		1		34		1
Common stock equity	1,512		51		1,484		51
	$	2,986	100	%	$	2,908	100	%

HEI’s short-term borrowings and HEI’s line of credit facility were as follows:

	Six months ended June 30, 2011		Balance
(in millions)	Average balance		June 30, 2011		December 31, 2010
Short-term borrowings(1)
Commercial paper	$	11	$	—	$	25
Line of credit draws	—		—		—
Undrawn capacity under HEI’s line of credit facility (expiring May 7, 2013)	N/A		125		125

(1) This table does not include HECO’s separate commercial paper issuances and line of credit facilities and draws, which are discussed below under “Electric utility—Financial Condition—Liquidity and capital resources.” At July 21, 2011, HEI had no outstanding commercial paper and its line of credit facility was undrawn.

HEI has a line of credit facility of $125 million (see Note 13 of HEI’s “Notes to Consolidated Financial Statements”). There are customary conditions which must be met in order to draw on it, including compliance with its covenants (such as covenants preventing HEI’s subsidiaries from entering into agreements that restrict the ability of the subsidiaries to pay dividends to, or to repay borrowings from, HEI). In addition to customary defaults,

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HEI’s failure to maintain its financial ratios, as defined in the agreement, or meet other requirements may result in an event of default. For example, it is an event of default if HEI fails to maintain a nonconsolidated “Capitalization Ratio” (funded debt) of 50% or less (ratio of 20% as of June 30, 2011, as calculated under the agreement) and “Consolidated Net Worth” of at least $975 million (actual Net Worth of $1.6 billion as of June 30, 2011, as calculated under the agreement). The commitment fee and interest charges on drawn amounts under the agreement are subject to adjustment in the event of a change in HEI’s long-term credit ratings.

HEI raised $22 million through the issuance of approximately 0.9 million shares of common stock under the DRIP, the HEIRSP and the ASB 401(k) Plan during the six months ended June 30, 2011. On August 18, 2011, HEI will begin satisfying the requirements of the DRIP, HEIRSP, ASB 401(k) Plan and other plans through open market purchases of its common stock.

On March 24, 2011, HEI issued $125 million of Senior Notes via a private placement ($75 million of 4.41% notes due March 24, 2016 and $50 million of 5.67% notes due March 24, 2021). HEI used part of the net proceeds from the issuance of the notes to pay down commercial paper (originally issued to refinance $50 million of 4.23% medium-term notes that matured on March 15, 2011) and will ultimately use the remaining proceeds to refinance part of the $100 million of 6.141% medium-term notes that will mature on August 15, 2011. The notes contain customary representation and warranties, affirmative and negative covenants, and events of default (the occurrence of which may result in some or all of the notes then outstanding becoming immediately due and payable) and provisions requiring the maintenance by HEI of certain financial ratios generally consistent with those in HEI’s revolving noncollateralized credit agreement, expiring on May 7, 2013. For example, it is an event of default if HEI fails to maintain an unconsolidated “Capitalization Ratio” (funded debt) of 50% or less or “Consolidated Net Worth” of at least $975 million.

For the first six month of 2011, net cash provided by operating activities of consolidated HEI was $55 million. Net cash used by investing activities for the same period was $214 million, primarily due to net increases in ASB’s loans held for investment and investment securities and mortgage-related securities and HECO’s consolidated capital expenditures. Net cash provided by financing activities during this period was $95 million as a result of several factors, including net increases in long-term debt, deposit liabilities and retail repurchase agreements and proceeds from the issuance of common stock under HEI plans, partly offset by decreases in short-term borrowings and the payment of common stock dividends. Other than capital contributions from their parent company, intercompany services (and related intercompany payables and receivables), HECO’s periodic short-term borrowings from HEI (and related interest) and the payment of dividends to HEI, the electric utility and bank segments are largely autonomous in their operating, investing and financing activities. (See the electric utility and bank segments’ discussions of their cash flows in their respective “Financial condition—Liquidity and capital resources” sections below.) During the first six months of 2011, HECO and ASB paid dividends to HEI of $35 million and $28 million, respectively.

CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS AND FINANCIAL CONDITION

The Company’s results of operations and financial condition can be affected by numerous factors, many of which are beyond the Company’s control and could cause future results of operations to differ materially from historical results. For information about certain of these factors, see pages 52 to 53, 72 to 76, and 86 to 89 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2010 Form 10-K.

Additional factors that may affect future results and financial condition are described above on pages iv and v under “Forward-Looking Statements.”

MATERIAL ESTIMATES AND CRITICAL ACCOUNTING POLICIES

In preparing financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ significantly from those estimates.

In accordance with SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” management has identified the accounting policies it believes to be the most critical to the Company’s financial statements—that is, management believes that these policies are both the most important to the portrayal of the Company’s financial condition and results of operations, and currently require management’s most difficult, subjective or complex judgments.

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For information about these material estimates and critical accounting policies, see pages 53 to 54, 76 to 77, and 89 of HEI’s MD&A included in Part II, Item 7 of HEI’s 2010 Form 10-K.

Following are discussions of the results of operations, liquidity and capital resources of the electric utility and bank segments.

Electric utility

RESULTS OF OPERATIONS

(dollars in thousands,	Three months ended June 30				%
except per barrel amounts)	2011		2010		change		Primary reason(s) for significant change
Revenues	$	728,738	$	584,095	25		Higher fuel oil and purchased power costs, the effects of which are generally passed on to customers ($137 million), decoupling revenue adjustment (RBA) at HECO ($3 million), rate base revenue adjustment mechanism (RAM) and O&M RAM at HECO ($1 million), HELCO test year 2010 ($1 million) and MECO test year 2010 ($2 million) interim rate increases.
Expenses
Fuel oil	312,141		215,322		45		Higher fuel oil costs and more KWHs generated

Purchased power	171,737		139,513		23		Higher fuel costs partially offset by less KWHs purchased

Other operation	67,388		60,254		12		See “Results — three months ended June 30, 2011” below

Maintenance	31,276		32,223		(3	)	See “Results — three months ended June 30, 2011” below

Depreciation	36,258		38,649		(6	)	Lower depreciation rates implemented in conjunction with the HELCO and MECO test year 2010 interim D&Os

Taxes, other than income taxes	67,152		54,170		24		Increase in revenues

Other	268		2,529		(89	)	Includes write-down of investment in combined heat and power system in 2010

Operating income	42,518		41,435		3		See “Results — three months ended June 30, 2011” below

Net income for common stock	17,024		17,642		(4	)	Higher operating income, more than offset by higher income taxes and lower AFUDC due to HECO’s EOTP being placed into service in June 2010

Kilowatthour sales (millions)	2,361		2,374		(1	)

Wet-bulb temperature (Oahu average; degrees Fahrenheit)	70.5		67.9		4

Cooling degree days (Oahu)	1,257		1,210		4

Average fuel oil cost per barrel	$	123.69	$	86.38	43

Customer accounts (end of period)	445,427		442,936		1

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(dollars in thousands,	Six months ended June 30				%
except per barrel amounts)	2011		2010		change		Primary reason(s) for significant change
Revenues	$	1,374,073	$	1,132,206	21		Higher fuel oil and purchased power costs, the effects of which are generally passed on to customers ($222 million), higher KWH sales ($9 million), decoupling revenue adjustment (RBA) at HECO ($2 million), rate base RAM and O&M RAM at HECO ($1 million), HELCO test year 2010 ($3 million) and MECO test year 2010 ($4 million) interim rate increases.
Expenses
Fuel oil	573,001		427,074		34		Higher fuel oil costs and more KWHs generated

Purchased power	319,695		256,295		25		Higher fuel costs and more KWHs purchased

Other operation	132,919		119,498		11		See “Results — six months ended June 30, 2011” below

Maintenance	60,472		59,276		2		See “Results — six months ended June 30, 2011” below

Depreciation	72,690		77,291		(6	)	Lower depreciation rates implemented in conjunction with the HELCO and MECO test year 2010 interim D&Os

Taxes, other than income taxes	127,147		105,961		20		Increase in revenues

Other	423		2,767		(85	)	Includes write-down of investment in combined heat and power system in 2010

Operating income	87,726		84,044		4		See “Results — six months ended June 30, 2011” below

Net income for common stock	36,213		35,694		1		Higher operating income, partly offset by higher income taxes and lower AFUDC due to HECO’s EOTP being placed into service in June 2010

Kilowatthour sales (millions)	4,711		4,647		1

Wet-bulb temperature (Oahu average; degrees Fahrenheit)	68.8		66.8		3

Cooling degree days (Oahu)	2,177		2,067		5

Average fuel oil cost per barrel	$	112.23	$	84.13	33

Customer accounts (end of period)	445,427		442,936		1

The electric utilities had effective tax rates for the second quarters of 2011 and 2010 of 39% and 36%, respectively, and for the first six months of 2011 and 2010 of 38% and 37%, respectively.

See “Economic conditions” in the “HEI Consolidated” section above.

Results — three months ended June 30, 2011. Operating income for the second quarter of 2011 increased by 3% when compared to the same quarter in 2010 due primarily to interim rate relief and lower maintenance and depreciation expense, partly offset by higher “Other operation” expenses. Maintenance expenses decreased $1 million due to lower overhaul cost, partially offset by higher vegetation and substation maintenance. “Other operation” expenses increased by $7 million in the second quarter of 2011 compared to the same period in 2010 primarily due to higher transmission and distribution operation expenses ($1 million), administrative and general expenses, including reserves ($1 million), bad debt ($1 million), and higher DSM expense ($1 million) (see “Demand-side management programs” below) that are generally passed on to customers through surcharges.

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Results — six months ended June 30, 2011. Operating income for the first six months of 2011 increased by 4% when compared to the same period in 2010 due primarily to interim rate relief and higher sales, partly offset by higher “Other operation” and “Maintenance” (O&M) expenses and taxes other than income taxes. “Other operation” expenses increased by $13 million in the first six months of 2011 compared to the same period in 2010 primarily due to higher transmission and distribution operation expenses ($3 million), higher administrative and general expenses, including reserves ($2 million), bad debt ($1 million) and higher DSM expense ($2 million) (see “Demand-side management programs” below) that are generally passed on to customers through surcharges. Maintenance expenses increased $1 million due to higher transmission and distribution maintenance including higher vegetation and substation maintenance.

Utility strategic progress. In 2010 and the first six months of 2011, the utilities made significant progress in implementing their clean energy strategies and the PUC issued several important regulatory decisions, all of which are key steps to support Hawaii’s efforts to reduce its dependence on oil. Included in the PUC decisions were a number of interim and final rate case decisions (see table in “Most recent rate proceedings” below).

Regulatory. With PUC approval, HECO implemented on March 1, 2011 a new regulatory model that is intended to facilitate meeting the State’s goals to transition to a clean energy economy and achieve an aggressive renewable portfolio standard. The model, referred to as “decoupling,” delinks revenues from sales and includes annual revenue adjustments for O&M expenses and rate base additions. Decoupling provides for more timely cost recovery and earning on investments and should result in an improvement in the utilities’ under-earning situation over the last several years. Prior to and during the transition to decoupling, however, the utilities’ returns have been, and may continue to be, well below PUC-allowed returns, as illustrated in the following table:

%	Return on average common equity						Return on ratebase (RORB)
12 months ended June 30, 2011	HECO		HELCO		MECO		HECO		HELCO		MECO
Utility returns (rate-making method)	4.73		8.99		7.02		5.02		7.55		6.52
PUC-allowed returns	10.00		10.50		10.50		8.16		8.59		8.43
Difference	(5.27	)	(1.51	)	(3.48	)	(3.14	)	(1.04	)	(1.91	)

Under decoupling, the most significant drivers for improving the ROACE are:

1. spending within PUC approved amounts for major projects and completing projects on schedule;

2. managing O&M expenses relative to authorized O&M adjustments, especially during periods of increasing demand; and

3. rate case outcomes that cover O&M requirements and rate base items not included in the revenue adjustment mechanisms (RAMs).

Effective March 1, 2011, as part of the decoupling implementation, HECO established the revenue balancing account and started recording the difference between target revenues from its HECO 2009 rate case and actual revenues. Based on a PUC order clarifying the implementation of the RAM adjustment issued on May 20, 2011, HECO began accruing and collecting 2011 RAM revenues of $15 million in annual revenues, or $1.3 million per month, beginning June 1, 2011, which was superseded on July 26, 2011 by the implementation of interim rates in HECO’s 2011 general rate case (see “Most recent rate proceedings” below). Under the decoupling order, in future non-general rate case years, HECO will accrue and collect 7/12ths of the annual RAM adjusted revenues in one year and the remaining 5/12ths in the following year. HECO had expected to be able to accrue RAM-adjusted revenues from January 1 of each RAM period. HECO’s Oahu goal of earning within 100 basis points of its allowed ROACE in 2012 will be more difficult to achieve than expected as a result of this proration of RAM revenues.

Also critical to closing the ROACE gap are HECO’s 2011 rate case, decoupling implementation for HELCO and MECO, and getting timely recovery of completed software project costs. The HECO 2011 rate case interim D&O reset target revenues, O&M expenses and rate base for the decoupling mechanisms until a final D&O is issued. The utilities expect 2011 O&M expenses, excluding DSM expenses, will be managed to the levels included in interim rates.

Future earnings growth are also dependent on rate base growth. The utilities have increased their five-year 2011-2015 capital expenditures forecast to $2.2 billion from $1.6 billion for the 2010-2014 forecast, with an

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expected compounded annual rate base growth rate of approximately 5%. Many of the major initiatives within this forecast are expected to be completed beyond the 5-year period. Four major initiatives comprise approximately 40% of the 5-year plan: (1) replacing aging infrastructure; (2) environmental compliance; (3) fuel infrastructure investments; and (4) infrastructure investments to integrate renewables into the system. Estimates for these projects could change with time, based on external factors such as the timing and technical requirements for environmental compliance.

Most recent rate proceedings. The electric utilities initiate PUC proceedings from time to time to request electric rate increases to cover rising operating costs and the cost of plant and equipment, including the cost of new capital projects to maintain and improve service reliability. The PUC may grant an interim increase within 10 to 11 months following the filing of an application, but there is no guarantee of such an interim increase and interim amounts collected are refundable, with interest, to the extent they exceed the amount approved in the PUC’s final D&O. The timing and amount of any final increase is determined at the discretion of the PUC. The adoption of revenue, expense, rate base and cost of capital amounts (including the ROACE and RORB) for purposes of an interim rate increase does not commit the PUC to accept any such amounts in its final D&O.

On July 22, 2011, the PUC issued an interim D&O granting HECO a net increase of $38.2 million in annual revenues, or 2.2%, net of the revenues currently being recovered through the decoupling Revenue Adjustment Mechanism (RAM), effective July 26, 2011. Including the RAM revenues, the total annual interim increase is $53.2 million or 3.1%. The interim increase is based on, and is substantially the same as, the settlement agreement executed and filed on July 5, 2011 by HECO, the Consumer Advocate and the Department of Defense (the parties in the proceeding). The interim increase reflects the new depreciation rates and methods approved by the PUC in a separate proceeding, which will result in a $2 million decrease in depreciation expense effective with interim rates to the end of 2011. The PUC did not approve the portion of the settlement agreement to allow deferral of certain costs amounting to approximately $3.2 million for 2011 (most of which have not yet been expended, including costs related to project management for the interisland wind project and undersea cable system sourcing). In the interim D&O, the PUC indicated it has not made a final determination on whether a labor expense adjustment is appropriate for this rate case, but finds that an adjustment is not necessary for purposes of the interim D&O, and will consider the reasonableness of such costs in light of current economic conditions in an evidentiary hearing scheduled in September 2011. See “Major projects” in Note 5 to HECO’s “Notes to Consolidated Financial Statements” for a discussion of the deferral of project costs in the interim D&O.

The following table summarizes certain details of each utility’s most recent rate cases, including the details of the increases requested, whether the utility and the Consumer Advocate reached a settlement that they proposed to the PUC, the details of increases granted in interim and final PUC D&Os, or whether an interim or final PUC D&O remains pending.

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Test year (dollars in millions)	Date (applied/ implemented)	Amount		% over rates in effect		ROACE		RORB		Ratebase		% Common equity		Stipulated agreement reached with Consumer Advocate	Reflects decoupling

HECO
2007
Request	12/22/06	$	99.6	7.1	%	11.25	%	8.92	%	$	1,214	55.10	%	Yes	No
Interim increase	10/22/07	70.0		5.0		10.70		8.62		1,158		55.10			No
Interim increase (adjusted)	6/20/08	77.9		5.6		10.70		8.62		1,158		55.10			No
Final increase	3/1/11	77.5		5.5		10.70		8.62		1,158		55.10			No
2009
Request (1)	7/3/08	$	97.0	5.2	%	11.25	%	8.81	%	$	1,408	54.30	%	Yes	No
Interim increase (1st)	8/3/09	61.1		4.7		10.50		8.45		1,169		55.81			No
Interim increase (2nd, plus 1st)	2/20/10	73.8		5.7		10.50		8.45		1,251		55.81			No
Final increase (2)	3/1/11	66.4		5.1		10.00		8.16		1,250		55.81			Yes
2011 (3)
Request	7/30/10	$	113.5	6.6	%	10.75	%	8.54	%	$	1,569	56.29	%	Yes	Yes
Interim increase	7/22/11	53.2		3.1		10.00		8.11		1,354		56.29			Yes
Final increase	Pending
HELCO
2006
Request	5/5/06	$	29.9	9.2	%	11.25	%	8.65	%	$	369	50.83	%	Yes	No
Interim increase	4/5/07	24.6		7.6		10.70		8.33		357		51.19			No
Final increase (4)	1/14/11	24.6		7.6		10.70		8.33		357		51.19			No
2010
Request (5)	12/9/09	$	20.9	6.0	%	10.75	%	8.73	%	$	487	55.91	%	Yes	Yes
Interim increase	1/14/11	6.0		1.7		10.50		8.59		465		55.91			No
Final increase	Pending
MECO
2007
Request	2/23/07	$	19.0	5.3	%	11.25	%	8.98	%	$	386	54.89	%	Yes	No
Interim increase	12/21/07	13.2		3.7		10.70		8.67		383		54.89			No
Final increase	1/12/11	13.2		3.7		10.70		8.67		383		54.89			No
2010
Request	9/30/09	$	28.2	9.7	%	10.75	%	8.57	%	$	390	56.86	%	Yes	Yes
Interim increase	8/1/10	10.3		3.3		10.50		8.43		387		56.86			No
Interim increase (adjusted)	1/12/11	8.5		2.7		10.50		8.43		387		56.86			No
Final increase	Pending
2012
Request (6)	7/22/11	$	27.5	6.7	%	11.00	%	8.72	%	$	393	56.85	%		Yes

Note: The “Request Date” reflects the application filing date for the rate proceeding. All other line items reflect the effective dates of the revised schedules and tariffs as a result of PUC-approved increases. In May 2011, MECO filed a Notice of Intent to file an application for a general rate increase, using a 2012 test year.

(1) In April 2009, HECO reduced this rate increase request by $6.2 million because a new Customer Information System would not be placed in service as originally planned (see Note 5 of HECO’s “Notes to Consolidated Financial Statements”).

(2) Because the final increase was $7.4 million less in annual revenues, HECO refunded $2.1 million to customers (including interest) in February 2011.

(3) HECO filed a request with the PUC for a general rate increase of $113.5 million, based on a 2011 test year and without the then estimated impacts of the implementation of decoupling as proposed in the PUC’s separate decoupling proceeding and depreciation rates and methodology as proposed by HECO in a separate depreciation proceeding. Including the estimated effects of the implementation of decoupling at the time, the effective revenue request was $94.0 million, or 5.4%. HECO’s request was primarily to pay for major capital projects and higher O&M costs to maintain and improve service reliability and to recover the costs for several proposed programs to help reduce Hawaii’s dependence on imported oil, and to further increase reliability and fuel security.

The $53.2 million interim increase includes $15 million in annual revenues already being recovered through the decoupling RAM.

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(4) Final D&O appealed by a participant in the rate case proceeding. The appeal is pending, but has not affected implementation of the rate increase.

(5) HELCO’s request was primarily to cover investments for system upgrade projects, two major transmission line upgrades and increasing O&M expenses.

(6) MECO’s request is required to pay for O&M expenses and additional investments in plant and equipment required to maintain and improve system reliability and to cover the increased costs to support the integration of more renewable energy generation.

Clean energy strategy. The utilities’ policy is to support efforts to increase renewable energy in Hawaii. The utilities believe their actions will help stabilize customer bills over time as they become less dependent on costly and price-volatile fossil fuel. The utilities’ clean energy strategy will also allow them to meet Hawaii’s renewable portfolio standard (RPS) law, which requires electric utilities to meet an RPS of 10%, 15%, 25% and 40% by December 31, 2010, 2015, 2020 and 2030, respectively. HECO met the 10% RPS for 2010 with a consolidated RPS of 20.7%, including saving from energy efficiency programs and solar water heating (or 9.5% without DSM energy savings). Energy savings resulting from energy efficiency programs and solar water heating will not count toward the RPS after 2014. With the continued support of the PUC and the Hawaii legislature, the utilities believe they will comfortably meet these RPS goals.

Recent developments in our clean energy strategy include:

· In January 2011, HELCO signed a 20-year contract, subject to PUC approval, with Aina Koa Pono-Ka’u LLC to supply 16 million gallons of biodiesel per year with initial consumption to begin by 2015.

· In February 2011, HECO successfully demonstrated that Unit 3 at its Kahe Power Plant could be powered using up to 100% biofuel.

· In February 2011, HELCO executed a PPA with Puna Geothermal Venture for the purchase of energy and capacity from an 8 MW expansion of PGV’s geothermal energy plant on the island of Hawaii.

· In February 2011, the PUC opened dockets related to MECO’s and HECO’s plans to proceed with competitive bidding processes to acquire up to approximately 50 MW and 300 MW, respectively, of new, renewable firm dispatchable capacity generation resources, with the initial increments expected to come on line in the 2015 and 2016 timeframes, respectively.

· In 2008, HECO issued an Oahu Renewable Energy Request for Proposals (2008 RFP) for combined renewable energy projects up to 100 MW. In February 2011, HECO executed a PPA with Kalaeloa Solar Two for a 5 MW PV project. Negotiations continue with a proposed wind project (70 MW).

· Included in the bids received in response to the 2008 RFP were proposals for two large scale neighbor island wind projects that would produce energy to be imported from Lanai and Molokai to Oahu via a yet-to-be-built undersea transmission cable system. HECO is negotiating with one of the project developers for a 200 MW wind farm to be built on Lanai. The other proposal did not advance after missing a key PUC deadline. Further, in July 2011, the PUC directed HECO to prepare a draft RFP for 200 MW or more of renewable energy to be delivered to the island of Oahu and submit the draft RFP to the PUC by mid-October 2011.

· In July 2011, HECO signed a contract with Pacific Biodiesel to supply at least 250,000 gallons of locally produced biodiesel for a new 8 MW standby generation facility at the Honolulu Airport that will be owned by the State and operated by HECO, targeted for operation in 2012.

Commitments and contingencies. See Note 5 of HECO’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements and interpretations. See Note 7 of HECO’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

Liquidity and capital resources. Management believes that HECO’s ability, and that of its subsidiaries, to generate cash, both internally from operations and externally from issuances of equity and debt securities, commercial paper and lines of credit, is adequate to maintain sufficient liquidity to fund their respective capital expenditures and investments and to cover debt, retirement benefits and other cash requirements for the foreseeable future.

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HECO’s consolidated capital structure was as follows:

(dollars in millions)	June 30, 2011				December 31, 2010
Short-term borrowings	$	—	—	%	$	—	—	%
Long-term debt, net	1,058		44		1,058		44
Preferred stock	34		1		34		1
Common stock equity	1,338		55		1,338		55
	$	2,430	100	%	$	2,430	100	%

HECO’s short-term borrowings (other than from HELCO and MECO) and line of credit facility were as follows:

	Average balance		Balance
(in millions)	Six months ended June 30, 2011		June 30, 2011		December 31, 2010
Short-term borrowings(1)
Commercial paper	$	—	$	—	$	—
Line of credit draws	—		—		—
Borrowings from HEI	—		—		—
Undrawn capacity under line of credit facility (expiring May 7, 2013)	N/A		175		175

(1) There were no external short-term borrowings during the first six months of 2011. At June 30, 2011, HECO had $37 million and $17 million of short-term borrowings from HELCO and MECO, respectively, which borrowings are eliminated in consolidation. At July 21, 2011, HECO had no outstanding commercial paper, its line of credit facility was undrawn, it had no borrowings from HEI and it had borrowings of $43 million and $25 million from HELCO and MECO, respectively.

HECO has a line of credit facility of $175 million (see Note 9 of HECO’s “Notes to Consolidated Financial Statements”). There are customary conditions that must be met in order to draw on it, including compliance with its covenants (such as covenants preventing HECO’s subsidiaries from entering into agreements that restrict their ability to pay dividends to, or to repay borrowings from, HECO, and restricting HECO’s and its subsidiaries’ ability to guarantee additional indebtedness of the subsidiaries if such additional debt would cause the subsidiary’s “Consolidated Subsidiary Funded Debt to Capitalization Ratio” to exceed 65% (actual ratios of 43% for HELCO and 42% for MECO as of June 30, 2011, as calculated under the agreement)). In addition to customary defaults, HECO’s failure to maintain its financial ratios, as defined in the agreement, or meet other requirements may result in an event of default. For example, it is an event of default if HECO fails to maintain a “Consolidated Capitalization Ratio” (equity) of at least 35% (actual ratio of 55% as of June 30, 2011, as calculated under the agreement). The commitment fee and interest charges on drawn amounts under the agreement are subject to adjustment in the event of a change in HECO’s long-term credit ratings.

On March 31, 2011, HECO, HELCO and MECO filed with the PUC an application for authorization to issue up to $250 million, $25 million and $25 million, respectively, in one or more registered public offerings or private placements of unsecured obligations bearing taxable interest on or before December 31, 2015. The proceeds are expected to be used to fund capital expenditures (including repaying short-term indebtedness incurred to fund capital expenditures) and to repay $57.5 million and $11.4 million of outstanding Special Purpose Revenue Bonds at their maturity in 2012 and 2014, respectively.

On May 31, 2011, HECO, HELCO and MECO filed with the PUC an application for the authorization to issue unsecured obligations bearing taxable interest and/or refunding Special Purpose Revenue Bonds prior to January 1, 2016 to refinance select series of outstanding revenue bonds up to $347 million, $95 million and $82 million, respectively.

Operating activities provided $16 million in net cash during the first six months of 2011. Investing activities for the same period used net cash of $77 million for capital expenditures, net of contributions in aid of construction. Financing activities for the same period used net cash of $36 million, primarily due the payment of $36 million of common and preferred dividends.

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Bank

RESULTS OF OPERATIONS

	Three months ended June 30				%
(in thousands)	2011		2010		change		Primary reason(s) for significant change
Revenues	$	66,318	$	71,632	(7	)	Lower interest income primarily due to lower earning asset balances as a result of the sale of substantial 1-4 family residential loan production in 2010 and lower residential loan production in 2011, lower yields on earning assets due to the lower interest rate environment and lower fee income on deposit liabilities as result of overdraft rules that took effect in mid-2010

Operating income	23,820		25,775		(8	)	Lower net interest and noninterest income and higher provision for loan losses, partly offset by lower noninterest expenses

Net income	15,195		16,131		(6	)	Lower operating income

Return on assets (%)	1.24		1.32				Lower net income

Efficiency ratio (%)	57		59				Lower noninterest expenses

	Six months ended June 30				%
(in thousands)	2011		2010		change		Primary reason(s) for significant change
Revenues	$	131,631	$	142,546	(8	)	Lower interest income primarily due to lower earning asset balances as a result of the sale of substantial 1-4 family residential loan production in 2010 and lower residential loan production in 2011, lower yields on earning assets due to the lower interest rate environment and lower fee income on deposit liabilities as a result of overdraft rules that took effect in mid-2010

Operating income	45,574		47,546		(4	)	Lower net interest and noninterest income and higher provision for loan losses, partly offset by lower noninterest expenses

Net income	29,046		29,867		(3	)	Lower operating income

Return on assets (%)	1.20		1.22				Lower net income

Efficiency ratio (%)	57		59				Lower noninterest expenses

See Note 4 of HEI’s “Notes to Consolidated Financial Statements” and “Economic conditions” in the “HEI Consolidated” section above.

In 2010, ASB successfully completed its multi-year Performance Improvement Project that began in 2008. The many initiatives of this project resulted in substantially improved profitability and reduced risk in 2010, which continued into the first six months of 2011.

For the six months ended June 30, 2011, ASB reported a strong 1.20% return on assets and 57% efficiency ratio, and ASB’s profitability metrics were in line with or better than the average of its high performing peers. Key drivers of this improved performance include:

1. ASB’s significant reduction of non-interest expense;

2. ASB’s reduction of its exposure to riskier non-core assets;

3. ASB’s lowering of its funding costs through its free checking product and lower CD balances; and

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4. ASB’s optimization of its balance sheet and capital efficiency and improvement of its capital ratios by exercising discipline through the downturn on what it selected to put on its balance sheet and holding additional capital to hedge against the downside of the credit cycle.

In addition, as Hawaii’s economy started to improve, ASB saw improvements in credit quality measures such as delinquent and nonaccrual loans and net charge-offs. ASB’s credit quality metrics through the down cycle has been better than the average of its peers due to its historic disciplined and conservative underwriting standards.

Management continues working to grow its bank franchise in Hawaii and remains focused on maintaining ASB as a high performing community bank with a targeted return on assets of 1.2%, net interest margin above 4% and an efficiency ratio in the mid-50s. Despite the revenue pressures across the banking industry, management expects ASB’s low-cost funding base, reduced cost structure and lower-risk profile to continue to deliver strong performance compared to industry averages.

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Results.

(dollars in thousands)	Three months ended June 30, 2011 vs. 2010	Six months ended June 30, 2011 vs. 2010

Net interest income	$45,672 vs $47,704	$91,578 vs $94,917
	Decrease due to lower balances and yields on loans and lower yields on investment and mortgage-related securities, partly offset by lower funding costs.

Net interest margin	4.07% vs 4.22%	4.11% vs 4.20%
	Decrease due to lower yields on the investment and mortgage-related securities portfolio and loans receivable, partly offset by lower cost of funds. See “Average balance sheet and net interest margin” below.

Average loans receivable	$3,595,485 vs $3,641,540	$3,571,040 vs $3,660,355
	Decrease due to lower average 1-4 family residential and residential land loan portfolios, partly offset by higher average home equity line of credit and commercial loan portfolios.
· Average 1-4 family residential loans	$2,030,256 vs $2,240,433	$2,046,224 vs $2,271,255
	Decrease due to the sale of substantial loan production in 2010 and lower residential loan production in 2011.
· Average residential land loans	$56,079 vs $86,822	$59,651 vs $89,905
	Decrease due to paydowns in the portfolio.
· Average home equity lines of credit	$456,341 vs $364,968	$444,104 vs $347,997
	Increase due to promotional campaigns during 2010 and 2011.
· Average commercial loans	$625,254 vs $543,876	$596,709 vs $544,947
	Increase due to strong commercial loan production in 2010 and the first half of 2011.

Average investment and mortgage-related securities	$689,463 vs $574,932	$674,477 vs $515,277
	Increase primarily due to the purchase of federal agency securities and obligations with excess liquidity.

Average deposit liabilities	$4,047,736 vs $4,021,920	$4,018,921 vs $4,018,382
	The shift in deposit mix from higher cost term certificates to lower cost savings and checking accounts has contributed to decreased funding costs.
· Average term certificates	$613,951 vs $791,248	$629,567 vs $819,729
	Decrease due to the outflow of term certificates throughout 2010 and year-to-date 2011 as ASB determined not to aggressively price its term certificate products.

· Core deposits	$3,433,785 vs $3,230,672	$3,389,354 vs $3,198,653
	Increased as ASB introduced new deposit products and attracted core deposits to partially offset the outflow of term certificates.

Average other borrowings	$250,407 vs $273,526	$246,418 vs $284,138
	Decrease due to an outflow of retail repurchase agreements

Provision for loan losses	$2,555 vs $990	$7,105 vs $6,349
	In the first six months of 2011, ASB recorded a provision for loan losses primarily due to the net charge-offs during the period for 1-4 family, residential land, and commercial loans. The second quarter 2011 provision for loan losses was lower than the provision for the first quarter of 2011 as a result of continued modest improvement in loan credit quality and portfolio mix. In the second quarter of 2010, ASB released loan loss reserves totaling $2.4 million on a commercial loan that was sold during the quarter and a commercial real estate construction loan that was successfully completed and fully leased and reclassified to an income property commercial real estate loan from a higher risk construction loan classification.

Noninterest income	$16,877 vs $18,658	$32,324 vs $36,510
	Decrease in noninterest income was primarily due to lower deposit liability fees as a result of new overdraft fee regulations, which took effect in mid-2010, partly offset by nonrecurring insurance proceeds. See “Noninterest income and expenses” below.

Noninterest expenses	$36,188 vs $39,625	$71,264 vs $77,595
	Decrease in noninterest expense primarily due to lower data processing expense as a result of ASB’s conversion to Fiserv Inc.’s bank platform system in May 2010. See “Noninterest income and expenses” below.

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Average balance sheet and net interest margin. ASB’s average balances, together with interest and dividend income earned and accrued, and resulting yields and costs were as follows:

	2011						2010
Three months ended June 30 (dollars in thousands)	Average balance			Interest		Average rate (%)	Average balance			Interest		Average rate (%)
Assets:
Other investments (1)	$	223,676		$	79	0.14	$	313,319		$	137	0.17
Investment and mortgage-related securities	689,463			3,836		2.23	574,932			3,509		2.44
Loans receivable (2)	3,595,485			45,648		5.08	3,641,540			49,328		5.42
Total interest-earning assets(3)	4,508,624			49,563		4.40	4,529,791			52,974		4.68
Allowance for loan losses	(40,078		)				(41,485		)
Non-interest-earning assets	417,899						407,839
Total assets	$	4,886,445					$	4,896,145
Liabilities and shareholder’s equity:
Interest-bearing demand and savings deposits	$	2,526,193		718		0.11	$	2,412,104		916		0.15
Time certificates	613,951			1,669		1.09	791,248			2,936		1.49
Total interest-bearing deposits	3,140,144			2,387		0.30	3,203,352			3,852		0.48
Other borrowings	250,407			1,382		2.19	273,526			1,418		2.05
Total interest-bearing liabilities	3,390,551			3,769		0.44	3,476,878			5,270		0.61
Non-interest bearing liabilities:
Deposits	907,592						818,568
Other	89,566						96,523
Shareholder’s equity	498,736						504,176
Total liabilities and shareholder’s equity	$	4,886,445					$	4,896,145
Net interest income				$	45,794					$	47,704
Net interest margin (%) (4)						4.07						4.22

	2011						2010
Six months ended June 30 (dollars in thousands)	Average balance			Interest		Average rate (%)	Average balance			Interest		Average rate (%)
Assets:
Other investments (1)	$	229,826		$	165	0.14	$	353,730		$	320	0.18
Investment and mortgage-related securities	674,477			7,645		2.27	515,277			6,643		2.58
Loans receivable (2)	3,571,040			91,745		5.15	3,660,355			99,073		5.43
Total interest-earning assets(3)	4,475,343			99,555		4.46	4,529,362			106,036		4.69
Allowance for loan losses	(39,953		)				(41,178		)
Non-interest-earning assets	417,109						410,398
Total assets	$	4,852,499					$	4,898,582
Liabilities and shareholder’s equity:
Interest-bearing demand and savings deposits	$	2,493,674		1,422		0.11	$	2,390,957		1,956		0.17
Time certificates	629,567			3,558		1.14	819,729			6,319		1.55
Total interest-bearing deposits	3,123,241			4,980		0.32	3,210,686			8,275		0.52
Other borrowings	246,418			2,749		2.22	284,138			2,844		1.99
Total interest-bearing liabilities	3,369,659			7,729		0.46	3,494,824			11,119		0.64
Non-interest bearing liabilities:
Deposits	895,680						807,696
Other	90,536						94,694
Shareholder’s equity	496,624						501,368
Total liabilities and shareholder’s equity	$	4,852,499					$	4,898,582
Net interest income				$	91,826					$	94,917
Net interest margin (%) (4)						4.11						4.20

(1) Includes federal funds sold, interest bearing deposits and stock in the FHLB of Seattle ($98 million as of June 30, 2011).

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(2) Includes loan fees of $0.6 million and $1.2 million for the three months ended June 30, 2011 and 2010, respectively, and $1.8 million and $2.6 million for the six months ended June 30, 2011 and 2010, respectively; includes interest accrued prior to suspension of interest accrual on nonaccrual loans; and includes nonaccrual loans.

(3) Interest income includes taxable equivalent basis adjustments, based upon a federal statutory tax rate of 35%, of $0.1 million and nil for the three months ended June 30, 2011 and 2010, respectively, and $0.2 million and nil for the six months ended June 30, 2011 and 2010, respectively.

(4) Net interest income as a percentage of average earning assets.

Earning assets, costing liabilities and other factors. Earnings of ASB depend primarily on net interest income, which is the difference between interest earned on earning assets and interest paid on costing liabilities. The current interest rate environment is impacted by disruptions in the financial markets and these conditions may have a negative impact on ASB’s net interest margin.

Loan originations and mortgage-related securities are ASB’s primary sources of earning assets.

Loan portfolio. ASB’s loan volumes and yields are affected by market interest rates, competition, demand for financing, availability of funds and management’s responses to these factors. The composition of ASB’s loan portfolio was as follows:

	June 30, 2011				December 31, 2010
(dollars in thousands)	Balance			% of total	Balance			% of total
Real estate loans:
Residential 1-4 family	$	2,028,502		55.8	$	2,087,813		58.9
Commercial real estate	321,967			8.9	300,689			8.5
Home equity line of credit	466,783			12.8	416,453			11.7
Residential land	51,901			1.4	65,599			1.8
Commercial construction	38,419			1.1	38,079			1.1
Residential construction	3,738			0.1	5,602			0.2
Total real estate loans, net	2,911,310			80.1	2,914,235			82.2
Commercial loans	640,221			17.6	551,683			15.5
Consumer loans	83,059			2.3	80,138			2.3
	3,634,590			100.0	3,546,056			100.0
Less: Deferred fees and discounts	(14,889		)		(15,530		)
Allowance for loan losses	(39,283		)		(40,646		)
Total loans, net	$	3,580,418			$	3,489,880

The increase in the total loan portfolio during the first six months of 2011 was primarily due to an increase in ASB’s commercial, commercial real estate and home equity lines of credit loan portfolios, partly offset by a decrease in residential loans.

Loan portfolio risk elements. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

Investment and mortgage-related securities. ASB’s investment portfolio was comprised as follows:

	June 30, 2011		December 31,2010
Federal agency obligations	41	%	47	%
Mortgage-related securities — FNMA, FHLMC and GNMA	53		47
Municipal bonds	6		6
	100	%	100	%

Principal and interest on mortgage-related securities issued by Federal National Mortgage Association (FNMA), Federal Home Loan Mortgage Corporation (FHLMC) and Government National Mortgage Association (GNMA) are guaranteed by the issuer, and the securities carry implied AAA ratings.

Deposits and other borrowings. Deposits continue to be the largest source of funds for ASB and are affected by market interest rates, competition and management’s responses to these factors. Core deposits continue to be strong, as depositors remain risk adverse. Advances from the FHLB of Seattle and securities sold under agreements to repurchase continue to be additional sources of funds. As of June 30, 2011 and December 31, 2010, ASB’s costing liabilities consisted of 94% deposits and 6% other borrowings. The weighted average cost of

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deposits for the six months ended June 30, 2011 was 0.25%, compared to 0.42% for the six months ended June 30, 2010.

Noninterest income and expenses. ASB’s noninterest income and expenses, including detail of other income and expenses, were as follows:

	Three months ended June 30				Six months ended June 30
(in thousands)	2011		2010		2011		2010
Fees from other financial services	$	7,240	$	6,649	$	14,186	$	13,063
Fee income on deposit liabilities	4,599		7,891		9,048		15,411
Fee income on other financial products	1,861		1,735		3,534		3,260
Net gains (losses) on available-for-sale securities	5		—		5		—
Other income
Gain on sale of loans	518		1,078		1,176		2,120
Bank-owned life insurance	2,142		988		3,111		1,994
Other	512		317		1,264		662
Total noninterest income	$	16,877	$	18,658	$	32,324	$	36,510

	Three months ended June 30				Six months ended June 30
(in thousands)	2011		2010		2011		2010
Compensation and benefits	$	18,166	$	18,907	$	35,671	$	36,309
Occupancy	4,288		4,216		8,528		8,441
Data processing	2,058		4,564		4,028		8,902
Services	1,949		1,845		3,720		3,573
Equipment	1,772		1,640		3,429		3,349
Other
FDIC insurance premium	876		1,599		2,303		3,258
Marketing	710		370		1,351		1,324
Office supplies, printing and postage	926		1,127		1,844		1,994
Communication	444		512		831		1,009
Other	4,999		4,845		9,559		9,436
Total noninterest expense	$	36,188	$	39,625	$	71,264	$	77,595

Allowance for loan losses. See Note 4 of HEI’s “Notes to Consolidated Financial Statement” for breakout of allowance for loan losses by loan type.

	Six months ended June 30							Year ended December 31
(dollars in thousands)	2011				2010			2010
Allowance for loan losses, January 1	$	40,646			$	41,679		$	41,679
Net charge-offs	(8,468			)	(10,955		)	(21,927			)
Provision for loan losses	7,105				6,349			20,894
Allowance for loan losses, end of period	$	39,283			$	37,073		$	40,646
Ratio of allowance for loan losses, end of period, to end of period loans outstanding	1.09			%	1.03		%	1.15			%
Ratio of net charge-offs during the period to average loans outstanding (annualized)	0.47			%	0.60		%	0.61			%
Nonaccrual loans	$		58,108		$	59,872		$		58,855

Other factors. Interest rate risk is a significant risk of ASB’s operations and also represents a market risk factor affecting the fair value of ASB’s investment securities. Increases and decreases in prevailing interest rates generally translate into decreases and increases in fair value of those instruments. In addition, changes in credit spreads also impact the fair values of those instruments.

Although higher long-term interest rates or other conditions in credit markets (such as the effects of the deteriorated subprime market) could reduce the market value of available-for-sale investment and mortgage-related securities and reduce shareholder’s equity through a balance sheet charge to accumulated other comprehensive income (AOCI), this reduction in the market value of investments and mortgage-related securities

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would not result in a charge to net income in the absence of a sale of such securities or an “other-than-temporary” impairment in the value of the securities. As of June 30, 2011 and December 31, 2010, the unrealized gains, net of taxes, on available-for-sale investments and mortgage-related securities (including securities pledged for repurchase agreements) in AOCI was $7 million and $4 million, respectively. See “Item 3. Quantitative and qualitative disclosures about market risk.”

Legislation and regulation. ASB is subject to extensive regulation, principally by the Office of Thrift Supervision (OTS), whose regulatory functions are to be transferred to the Office of the Comptroller of the Currency (OCC) as described below, and the Federal Deposit Insurance Corporation (FDIC). Depending on ASB’s level of regulatory capital and other considerations, these regulations could restrict the ability of ASB to compete with other institutions and to pay dividends to its shareholder. See the discussion below under “Liquidity and capital resources.”

Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). Regulation of the financial services industry, including regulation of HEI and ASB, will undergo substantial changes as a result of the enactment of the Dodd-Frank Act, which became law in July 2010. Importantly for HEI and ASB, under the Dodd-Frank Act, on July 21, 2011, all of the functions of the OTS transferred to the OCC, the FDIC, the Federal Reserve and the Consumer Financial Protection Bureau. Supervision and regulation of HEI, as a thrift holding company, moved to the Federal Reserve, and supervision and regulation of ASB, as a federally chartered savings bank, moved to the OCC. While the laws and regulations applicable to HEI and ASB did not generally change—the Home Owners Loan Act and regulations issued thereunder still apply—the applicable laws and regulations are being interpreted, and new and amended regulations may be adopted, by the Federal Reserve and the OCC. HEI will for the first time be subject to minimum consolidated capital requirements, and ASB may be required to be supervised through ASHI, its intermediate holding company. HEI will continue to be required to serve as a source of strength to ASB in the event of its financial distress. The Dodd-Frank Act also imposes new restrictions on the ability of a savings bank to pay dividends should it fail to remain a qualified thrift lender.

More stringent affiliate transaction rules now apply to ASB in the securities lending, repurchase agreement and derivatives areas. Standards were raised with respect to the ability of ASB to merge with or acquire another institution. In reviewing a potential merger or acquisition, the approving federal agency will need to consider the extent to which the proposed transaction will result in “greater or more concentrated risks to the stability of the U.S. banking or financial system.” Based on the changes to the assessment base and rates, ASB anticipates a reduction in its annual FDIC assessment of approximately $2 million. ASB may be affected by the provision of the Dodd-Frank Act that repeals, effective in July 2011, the prohibition on payments of interest by banks or savings associations on demand deposit accounts for businesses.

The Dodd-Frank Act establishes a Consumer Financial Protection Bureau (Bureau) that will have authority to prohibit practices it finds to be unfair, deceptive or abusive, and it may also issue rules requiring specified disclosures and the use of new model forms. ASB may also be subject to new state regulation because of a provision in the Dodd-Frank Act.

The Dodd-Frank Act also adopts a number of provisions that will impact the mortgage industry, including the imposition of new specific duties on the part of mortgage originators (such as ASB) to act in the best interests of consumers and to take steps to ensure that consumers will have the capability to repay loans they may obtain, as well as provisions imposing new disclosure requirements and requiring appraisal reforms. Regulations are required to be adopted within 18 months after the date that is to be specified by the Secretary of the Treasury for the transfer of consumer protection power to the Bureau.

The “Durbin Amendment” to the Dodd-Frank Act requires the Federal Reserve to issue rules to ensure that debit card interchange fees are “reasonable and proportional” to the processing costs incurred. Previously, the Federal Reserve had proposed a cap on debit card interchange fees that card issuers can receive up to 12 cents per transaction. In June 2011, however, the Federal Reserve issued a final rule establishing standards for debit card interchange fees and prohibiting network exclusivity arrangements and routing restrictions. Under the final rule, effective October 1, 2011, the maximum permissible interchange fee that an issuer may receive for an electronic debit transaction is 21-24 cents, depending on certain components. ASB currently earns an average of 52 cents per transaction. As specified in the

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Dodd-Frank Act, these regulations will exempt banks like ASB with less than $10 billion in assets. However, market pressures could very well push the impact down to all banks.

Many of the provisions of the Dodd-Frank Act, as amended, will not become effective until implementing regulations are issued and effective. Thus, management cannot predict the ultimate impact of the Dodd-Frank Act, as amended, on the Company or ASB at this time. Nor can management predict the impact or substance of other future federal or state legislation or regulation, or the application thereof.

Overdraft rules. On November 12, 2009, the Board of Governors of the Federal Reserve System announced that it amended Regulation E (which implements the Electronic Fund Transfer Act) to limit the ability of a financial institution to assess an overdraft fee for paying automated teller machine or one-time debit card transactions that overdraw a consumer’s account, unless the consumer affirmatively consents, or opts in, to the institution’s payment of overdrafts for those transactions. These new rules applied on July 1, 2010 for new accounts and August 15, 2010 for existing accounts. In 2009, these types of overdraft fees totaled approximately $15 million pretax for ASB. The amendment had a negative impact on ASB’s noninterest income of approximately $6.0 million pretax for the first six months of 2011 compared to the first six months of 2010.

Commitments and contingencies. See Note 4 of HEI’s “Notes to Consolidated Financial Statements.”

Recent accounting pronouncements and interpretations. See Note 12 of HEI’s “Notes to Consolidated Financial Statements.”

FINANCIAL CONDITION

Liquidity and capital resources.

(dollars in millions)	June 30, 2011		December 31, 2010		% change
Total assets	$	4,891	$	4,797	2
Available-for-sale investment and mortgage-related securities	711		678		5
Loans receivable, net	3,585		3,498		3
Deposit liabilities	4,055		3,975		2
Other bank borrowings	239		237		1

As of June 30, 2011, ASB was one of Hawaii’s largest financial institutions based on assets of $4.9 billion and deposits of $4.1 billion.

As of June 30, 2011, ASB’s unused FHLB borrowing capacity was approximately $1.1 billion. As of June 30, 2011, ASB had commitments to borrowers for loan commitments and unused lines and letters of credit of $1.3 billion. Management believes ASB’s current sources of funds will enable it to meet these obligations while maintaining liquidity at satisfactory levels.

For the first six months of 2011, net cash provided by ASB’s operating activities was $53 million. Net cash used during the same period by ASB’s investing activities was $133 million, primarily due to purchases of investment and mortgage-related securities of $193 million and a net increase in loans receivable of $105 million, offset by repayments of investment and mortgage-related securities of $162 million. Net cash provided in financing activities during this period was $53 million, primarily due to net increases in deposit liabilities and retail repurchase agreements of $80 million and $2 million, respectively, offset by the payment of $28 million in common stock dividends.

FDIC regulations restrict the ability of financial institutions that are not well-capitalized to compete on the same terms as well-capitalized institutions, such as by offering interest rates on deposits that are significantly higher than the rates offered by competing institutions. As of June 30, 2011, ASB was well-capitalized (minimum ratio requirements noted in parentheses) with a leverage ratio of 9.1% (5.0%), a Tier-1 risk-based capital ratio of 12.3% (6.0%) and a total risk-based capital ratio of 13.3% (10.0%). OTS approval is required before ASB can pay a dividend or otherwise make a capital distribution to HEI (through ASHI).

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company considers interest-rate risk (a non-trading market risk) to be a very significant market risk for ASB as it could potentially have a significant effect on the Company’s financial condition and results of operations. For additional quantitative and qualitative information about the Company’s market risks, see pages 90 to 92, HEI’s Quantitative and Qualitative Disclosures About Market Risk, in Part II, Item 7A of HEI’s 2010 Form 10-K and HECO’s Quantitative and Qualitative Disclosures About Market Risk, which is incorporated into Part II, Item 7A of HECO’s 2010 Form 10-K by reference to Exhibit 99.2.

ASB’s interest-rate risk sensitivity measures as of June 30, 2011 and December 31, 2010 constitute “forward-looking statements” and were as follows:

	June 30, 2011						December 31, 2010
Change in interest rates	Change in NII		NPV ratio		NPV ratio sensitivity*		Change in NII		NPV ratio		NPV ratio sensitivity*
(basis points)	Gradual change		Instantaneous change				Gradual change		Instantaneous change
+300	(2.0	)%	12.28	%	(205	)	(1.3	)%	12.04	%	(196	)
+200	(1.9	)	13.10		(123	)	(1.3	)	12.84		(116	)
+100	(0.9	)	13.79		(54	)	(0.8	)	13.52		(48	)
Base	—		14.33		—		—		14.00		—
-100	(0.5	)	14.44		11		(0.6	)	14.04		4

* Change from base case in basis points (bp).

ASB’s net interest income (NII) sensitivity was more sensitive for increases in rates as of June 30, 2011 compared to December 31, 2010 as changes in asset mix reduced maturing or repricing cash flows within the 1 year horizon. The base net portfolio value (NPV) ratio increased as of June 30, 2011 due to lower interest rates which led to an increase in the market value of the mortgage portfolio compared to December 31, 2010. There was a modest increase in the NPV sensitivity measure as of June 30, 2011 compared to December 31, 2010 as the balance sheet grew and shifted with increased investments and nonmortgage loans funded by deposits, cash and residential loan repayments.

The computation of the prospective effects of hypothetical interest rate changes on the NII sensitivity, NPV ratio, and NPV ratio sensitivity analyses is based on numerous assumptions, including relative levels of market interest rates, loan prepayments, balance changes and pricing strategies, and should not be relied upon as indicative of actual results. To the extent market conditions and other factors vary from the assumptions used in the simulation analysis, actual results may differ materially from the simulation results. Furthermore, NII sensitivity analysis measures the change in ASB’s twelve-month, pre-tax NII in alternate interest rate scenarios, and is intended to help management identify potential exposures in ASB’s current balance sheet and formulate appropriate strategies for managing interest rate risk. The simulation does not contemplate any actions that ASB management might undertake in response to changes in interest rates. Further, the changes in NII vary in the twelve-month simulation period and are not necessarily evenly distributed over the period. These analyses are for analytical purposes only and do not represent management’s views of future market movements, the level of future earnings, or the timing of any changes in earnings within the twelve month analysis horizon. The actual impact of changes in interest rates on NII will depend on the magnitude and speed with which rates change, actual changes in ASB’s balance sheet, and management’s responses to the changes in interest rates.

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Item 4. Controls and Procedures

HEI:

Changes in Internal Control over Financial Reporting

During the second quarter of 2011, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of the Company’s internal control over financial reporting as of June 30, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Constance H. Lau, HEI Chief Executive Officer, and James A. Ajello, HEI Chief Financial Officer, have evaluated the disclosure controls and procedures of HEI as of June 30, 2011. Based on their evaluations, as of June 30, 2011, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HEI in reports HEI files or submits under the Securities Exchange Act of 1934:

(1) is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2) is accumulated and communicated to HEI management, including HEI’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

HECO:

Changes in Internal Control over Financial Reporting

During the second quarter of 2011, there were no changes in internal control over financial reporting identified in connection with management’s evaluation of the effectiveness of HECO and its subsidiaries’ internal control over financial reporting as of June 30, 2011 that has materially affected, or is reasonably likely to materially affect, HECO and its subsidiaries’ internal control over financial reporting.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Richard M. Rosenblum, HECO Chief Executive Officer, and Tayne S. Y. Sekimura, HECO Chief Financial Officer, have evaluated the disclosure controls and procedures of HECO as of June 30, 2011. Based on their evaluations, as of June 30, 2011, they have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective in ensuring that information required to be disclosed by HECO in reports HECO files or submits under the Securities Exchange Act of 1934:

(1) is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and

(2) is accumulated and communicated to HECO management, including HECO’s principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The descriptions of legal proceedings (including judicial proceedings and proceedings before the PUC and environmental and other administrative agencies) in HEI’s Form 10-K (see “Part I. Item 3. Legal Proceedings” and proceedings referred to therein) and this 10-Q (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Note 4 of HEI’s “Notes to Consolidated Financial Statements” and HECO’s “Notes to Consolidated Financial Statements”) are incorporated by reference in this Item 1. With regard to any pending legal proceeding, alternative dispute resolution, such as mediation or settlement, may be pursued where appropriate, with such efforts typically maintained in confidence unless and until a resolution is achieved. Certain HEI subsidiaries (including HECO and its subsidiaries and ASB) may also be involved in ordinary routine PUC proceedings, environmental proceedings and litigation incidental to their respective businesses.

Item 1A. Risk Factors

For information about Risk Factors, see pages 28 to 37 of HEI’s 2010 Form 10-K, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Quantitative and Qualitative Disclosures about Market Risk,” HEI’s Consolidated Financial Statements and HECO’s Consolidated Financial Statements herein. Also, see “Forward-Looking Statements” on pages v and vi of HEI’s 2010 Form 10-K, as updated on pages iv and v herein.

Item 5. Other Information

A. Ratio of earnings to fixed charges.

	Six months ended June 30		Years ended December 31
	2011	2010	2010	2009	2008	2007	2006
HEI and Subsidiaries
Excluding interest on ASB deposits	2.66	2.81	2.89	2.29	2.06	1.78	2.08
Including interest on ASB deposits	2.51	2.55	2.64	1.95	1.71	1.52	1.73
HECO and Subsidiaries	2.76	2.69	2.88	2.99	3.48	2.43	3.14

See HEI Exhibit 12.1 and HECO Exhibit 12.2.

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Item 6. Exhibits

HEI Exhibit 4		Letter Amendment effective August 19, 2011, to Trust Agreement (dated as of February 1, 2000) between HEI, ASB and Fidelity Management Trust Company, as Trustee

HEI Exhibit 12.1		Hawaiian Electric Industries, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, six months ended June 30, 2011 and 2010 and years ended December 31, 2010, 2009, 2008, 2007 and 2006

HEI Exhibit 31.1		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Constance H. Lau (HEI Chief Executive Officer)

HEI Exhibit 31.2		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of James A. Ajello (HEI Chief Financial Officer)

HEI Exhibit 32.1		Written Statement of Constance H. Lau (HEI Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HEI Exhibit 32.2		Written Statement of James A. Ajello (HEI Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HECO Exhibit 12.2		Hawaiian Electric Company, Inc. and Subsidiaries Computation of ratio of earnings to fixed charges, six months ended June 30, 2011 and 2010 and years ended December 31, 2010, 2009, 2008, 2007 and 2006

HECO Exhibit 31.3		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Richard M. Rosenblum (HECO Chief Executive Officer)

HECO Exhibit 31.4		Certification Pursuant to Rule 13a-14 promulgated under the Securities Exchange Act of 1934 of Tayne S. Y. Sekimura (HECO Chief Financial Officer)

HECO Exhibit 32.3		Written Statement of Richard M. Rosenblum (HECO Chief Executive Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

HECO Exhibit 32.4		Written Statement of Tayne S. Y. Sekimura (HECO Chief Financial Officer) Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted by Section 906 of the Sarbanes-Oxley Act of 2002

Exhibit 101.INS		XBRL Instance Document

Exhibit 101.SCH		XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB		XBRL Taxonomy Extension Label Linkbase Document

Exhibit 101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signature of the undersigned companies shall be deemed to relate only to matters having reference to such companies and any subsidiaries thereof.

HAWAIIAN ELECTRIC INDUSTRIES, INC.				HAWAIIAN ELECTRIC COMPANY, INC.
			(Registrant)				(Registrant)


By	/s/ Constance H. Lau			By	/s/ Richard M. Rosenblum
	Constance H. Lau				Richard M. Rosenblum
	President and Chief Executive Officer				President and Chief Executive Officer
	(Principal Executive Officer of HEI)				(Principal Executive Officer of HECO)


By	/s/ James A. Ajello			By	/s/ Tayne S. Y. Sekimura
	James A. Ajello				Tayne S. Y. Sekimura
	Executive Vice President,				Senior Vice President
	Chief Financial Officer and Treasurer				and Chief Financial Officer
	(Principal Financial Officer of HEI)				(Principal Financial Officer of HECO)


By	/s/ David M. Kostecki			By	/s/ Patsy H. Nanbu
	David M. Kostecki				Patsy H. Nanbu
	Vice President-Finance, Controller				Controller
	and Chief Accounting Officer				(Principal Accounting Officer of HECO)
	(Principal Accounting Officer of HEI)

Date:		August 4, 2011			Date:	August 4, 2011